Download:
pdf |
pdfExhibit D
Summary of Development History and Complete Record of Development
Summary of Development History
Summary of Development History
The development record for proposed Reliability Standard TPL-007-2 is summarized
below.
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 selected to lead each project in accordance with Section
4.3 of the NERC Standards Process Manual. 2 For this project, the standard drafting team
consisted of industry experts, all with a diverse set of experiences. A roster of the Standard
Drafting team (“SDT”) members is included in Exhibit F.
II.
Standard Development History
A. Standard Authorization Request Development
Project 2013-03 – Geomagnetic Disturbance Mitigation was initiated to address
Commission directives in Order No. 830. 3 In Order No. 830, the Commission directed NERC to:
(1) Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
(2) Make related modifications to requirements pertaining to transformer thermal impact
assessments;
(3) Require collection of GMD-related data, which NERC is to make publicly available; and
(4) Require deadlines for Corrective Action Plans and GMD mitigating actions. 4
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2012).
The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
3
Order No. 830, Reliability Standard for Transmission System Planned Performance for Geomagnetic
Disturbance Events, 156 FERC ¶ 61,215, 81 Fed. Reg. 67,210 (2016).
4
Id.
2
1
The Commission directed NERC to file the modifications within 18 months of the
effective date of Order No. 830. A Standard Authorization Request (“SAR”) was posted for a 30day formal comment period from December 16, 2016 through January 20, 2017. The Standards
Committee accepted the SAR on March 16, 2017.
B. First Posting – Comment Period, Initial Ballot and Non-binding Poll
Proposed Reliability Standard TPL-007-2 and the associated Implementation Plan,
Violation Risk Factors, and Violation Severity Levels were posted for a 45-day formal public
comment period from June 28, 2017 through August 11, 2017, with a parallel initial ballot and
non-binding poll held during the last 10 days of the comment period from August 2, 2017
through August 11, 2017. The initial ballot received 79.87% quorum, and 72.67% approval. The
non-binding poll received 77.13% quorum and 69.19% of supportive opinions. There were 58
sets of responses, including comments from approximately 147 different individuals and
approximately 106 companies representing all 10 industry segments. 5
C. Final Ballot
Proposed Reliability Standard TPL-007-2 was posted for a 10-day final ballot period on
October 20, 2017 through October 30, 2017. The proposed Reliability Standard received a
quorum of 88.74% and an approval rating of 73.35%.
D. Board of Trustees Approval
Proposed Reliability Standard TPL-007-2 was adopted by the NERC Board of Trustees
on November 9, 2017. 6
5
NERC, Consideration of Comments, Project 2013-03 - Geomagnetic Disturbance Mitigation, (October
2017), available at
http://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Consideration_of_Comments_Oct
ober_2017.pdf.
6
NERC, Board of Trustees Agenda Package, Agenda Item 7b (Project 2013-03 - Geomagnetic Disturbance
Mitigation), available at
http://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board_Open_Meeting_Novemb
er_9_2017_Agenda_Package.pdf.
2
E. Implementation Plan Errata
On January 17, 2018, the Standards Committee approved an errata change to the TPL007-2 implementation plan. 7
7
NERC, Standards Committee Conference Call, Agenda Item 6 (Project 2013-03 TPL-007-2 Errata),
available at
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/Standards_Committee_Agenda_Packag
e_January_2018.pdf.
3
Complete Record of Development
Project 2013-03 Geomagnetic Disturbance Mitigation
Related Files
Status
A 10-day final ballot for TPL-007-2 - Transmission System Planned Performance for Geomagnetic
Disturbance Events concluded at 8 p.m. Eastern, Monday, October 30, 2017. The voting results can be
accessed via the links below. The standard will be submitted to the Board of Trustees for adoption and then filed
with the appropriate regulatory authorities.
Background:
On September 22, 2016, FERC issued Order No. 830 approving Reliability Standard TPL-007-1 − Transmission System
Planned Performance for Geomagnetic Disturbance Events. In the order, FERC directed NERC to develop certain
modifications to the Standard, or to develop other new or revised Standards. The revisions include:
•
•
•
•
Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact assessments;
Require collection of GMD-related data. NERC is directed to make data available; and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
FERC established a deadline of 18 months from the effective date of Order No. 830 for completing the revisions,
which is May 2018.
Standard Affected: TPL-007-1 - Transmission System Planned Performance for Geomagnetic Disturbance Events
Purpose/Industry Need:
Project 2013-03 will develop reliability standards to mitigate the risk of instability, uncontrolled separation, and
Cascading as a result of geomagnetic disturbances (GMDs) through application of Operating Procedures and
strategies that address potential impacts identified in a registered entity's assessment as directed in FERC Order 779
and FERC Order No. 830.
While the impacts of space weather are complex and depend on numerous factors, space weather has demonstrated
the potential to effect the reliable operation of the Bulk-Power System. During a GMD event, geomagneticallyinduced current (GIC) flow in transformers may cause half-cycle saturation, which can increase absorption of
Reactive Power, generate harmonic currents, and cause transformer hot spot heating. Increased transformer
Reactive Power absorption and harmonic currents associated with GMD events can also cause protection system
Misoperation and loss of Reactive Power sources, the combination of which can lead to voltage collapse.
<><><><><><><> <><><><><><><><><><><> <><><><><><><><><><><><><><><><><>
Draft
Action
Dates
Results
The Standards Committee approved the revised Implementation Plan on
January 17, 2018.
Revised
Implementation Plan
Clean (40)| Redline to Last
Posted (41)
Final Draft
Final Ballot
TPL-007-2
Clean (25) | Redline to
LastPosted (26)
Redline to Last Approved
(27)
Info (39)
Vote
10/20/17 10/30/17
Consideration
of Comments
Implementation Plan
Clean (28)| Redline to Last
Posted (29)
Supporting Materials
Supplemental GMD Event
White Paper
Clean (30) | Redline to Last
Posted (31)
Thermal Screening Criterion
White Paper
Clean (32)| Redline to Last
Posted (33)
Ballot
Results
Transformer Thermal
Impact Assessment White
Paper
Clean (34)| Redline to Last
Posted (35)
VRF/VSL Justification
Clean (36)| Redline to Last
Posted (37)
Consideration of
Directives (38)
Draft 1
TPL-007-2
Clean (8) | Redline to Last
Approved (9)
Initial Ballot and
Non-binding Poll
Updated Info (19)
Info (20)
Implementation Plan (10)
Vote
Supporting Materials
Comment Period
Supplemental GMD Event
White Paper (11)
Info (23)
Thermal Screening Criterion
White Paper
Clean (12) | Redline (13)
Ballot
Results (21)
08/02/17 –
08/11/17 Non-binding
Poll Results
(22)
06/28/17 –
08/11/17
Submit Comments
Join Ballot Pools
06/28/17 –
07/27/17
Info
07/25/17 Transformer Thermal
08/25/17
Send RSAW feedback
Impact Assessment White
to:RSAWfeedback@nerc.net
Paper
Comments Consideration of
Received Comments (24)
Clean (14) | Redline (15)
Unofficial Comment Form
(Word) (16)
VRF/VSL Justification (17)
Consideration of Directives
(18)
Draft Reliability Standard
Audit Worksheet (RSAW)
Clean | Redline to Last
Posted
The Standards Committee accepted the Standards Authorization Request on March 16, 2017.
Revised
Standard Authorization
03/17/17
Request
Clean (6) | Redline (7)
Standard Authorization
Request (1)
Informal Comment Period
Supporting Materials
Info (3)
Unofficial Comment Form
(Word) (2)
Submit Comments
12/16/16 – Comments Consideration of
01/20/17 Received (4) Comments (5)
Standards Authorization Request Form
When completed, email this form to:
sarcomm@nerc.com
NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
Modifications to Geomagnetic Disturbance Standards
Date Submitted:
December 1, 2016
SAR Requester Information
Name:
Frank Koza
Organization:
PJM Interconnection / Project 2013-03 SDT Chair
Telephone:
610-666-4228
E-mail:
frank.koza@pjm.com
SAR Type (Check as many as applicable)
New Standard
Withdrawal of existing Standard
Revision to existing Standard
Urgent Action
SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The goal of this project is to address the Federal Energy Regulatory Commission (Commission) directives
contained in Order No. 830 by modifying TPL-007-1 - Transmission System Planned Performance for
Geomagnetic Disturbance Events and the benchmark GMD event used in GMD Vulnerability
Assessments or by developing an equally efficient and effective alternative.
Industry Need (What is the industry problem this request is trying to solve?):
On September 22, 2016, the Commission issued Order No. 830 approving TPL-007-1. In the order, the
Commission directed NERC to develop certain modifications to the Standard, including:
Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact
assessments;
SAR Information
Require collection of GMD-related data, and for NERC to make it publicly available; and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
The Commission established a deadline of 18 months from the effective date of Order No. 830 for
completing the revisions, which is May 29, 2018.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The Standards Drafting Team (SDT) shall develop modifications to TPL-007-1 and the benchmark GMD
event that address Commission directives from Order No. 830. The work will include development of
Violation Risk Factors, Violation Severity Levels, and an Implementation Plan for the modified standards
within the deadline established by the Commission in Order No. 830.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDT shall address each of the Order No. 830 directives by developing modifications to requirements
in TPL-007-1 and related material, or the SDT shall develop an equally efficient and effective alternative.
To address concerns identified in Order No. 830, the Commission directed the following:
Benchmark GMD Event
[T]he Commission, as proposed in the NOPR, directs NERC to develop revisions to the benchmark
GMD event definition so that the reference peak geoelectric field amplitude component is not
based solely on spatially-averaged data.(P.44)
Without prejudging how NERC proposes to address the Commission’s directive, NERC’s response
to this directive should satisfy the NOPR’s concern that reliance on spatially-averaged data alone
does not address localized peaks that could potentially affect the reliable operation of the BulkPower System. (P.47)
Transformer Thermal Impact Assessment
Consistent with our determination above regarding the reference peak geoelectric field
amplitude value, the Commission directs NERC to revise Requirement R6 to require registered
entities to apply spatially averaged and non-spatially averaged peak geoelectric field values, or
some equally efficient and effective alternative, when conducting thermal impact assessments.
(P.65)
Collection of GMD Data
The Commission … adopts the NOPR proposal in relevant part and directs NERC to develop
revisions to Reliability Standard TPL-007-1 to require responsible entities to collect GIC
monitoring and magnetometer data as necessary to enable model validation and situational
awareness, including from any devices that must be added to meet this need. The NERC standard
drafting team should address the criteria for collecting GIC monitoring and magnetometer data...
Project 2013-03 Geomagnetic Disturbance Mitigation
December 1, 2016
2
SAR Information
and provide registered entities with sufficient guidance in terms of defining the data that must be
collected.... (P.88)
Each responsible entity that is a transmission owner should be required to collect necessary GIC
monitoring data. However, a transmission owner should be able to apply for an exemption from
the GIC monitoring data collection requirement if it demonstrates that little or no value would be
added to planning and operations. (P.91)
NERC may also propose to incorporate the GIC monitoring and magnetometer data collection
requirements in a different Reliability Standard....(P.91)
Deadlines for Corrective Action Plans and Mitigations
The Commission directs NERC to modify Reliability Standard TPL-007-1 to include a deadline of
one year from the completion of the GMD Vulnerability Assessments to complete the
development of corrective action plans. (P.101)
The Commission also directs NERC to modify Reliability Standard TPL-007-1 to include a two-year
deadline after the development of the corrective action plan to complete the implementation of
non-hardware mitigation and four-year deadline to complete hardware mitigation…. The
Commission agrees that NERC should consider extensions of time on a case-by-case basis. (P.102)
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Project 2013-03 Geomagnetic Disturbance Mitigation
December 1, 2016
3
Reliability Functions
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and Reactive Power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all 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.
Project 2013-03 Geomagnetic Disturbance Mitigation
December 1, 2016
4
Reliability and Market Interface Principles
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.
Does the proposed Standard 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.
Enter
(yes/no)
YES
YES
YES
YES
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Project 2013-03 Geomagnetic Disturbance Mitigation
December 1, 2016
Explanation
5
Regional Variances
Region
Explanation
FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC
Project 2013-03 Geomagnetic Disturbance Mitigation
December 1, 2016
6
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation
Standard Authorization Request
DO NOT use this form for submitting comments. Use the electronic form to submit comments on the
Standards Authorization Request (SAR). The electronic comment form must be completed by 8:00 p.m.
Eastern, Friday, January 20, 2017.
Documents and information about this project are available on the project page. If you have any
questions, contact Standards Developer, Mark Olson (via email), or at (404) 446-9760.
Background Information
On September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL-007-1 - Transmission System Planned Performance for Geomagnetic
Disturbance Events. In the order, FERC directed NERC to develop certain modifications to the Standard,
including:
•
•
•
•
Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact
assessments;
Require collection of GMD-related data, and for NERC to make it publicly available; and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
FERC established a deadline of 18 months from the effective date of Order No. 830 for completing the
revisions, which is May 2018.
The standard drafting team (SDT) developed the SAR to specifically address the directives in Order No.
830. The SAR is posted for stake holder comment to obtain input for the SDT on whether changes to the
SAR are needed to address the directives in Order No. 830.
Questions
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
1. Do you agree with the proposed scope for Project 2013-03 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 Standards Drafting Team (SDT) to consider, if desired.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation | December 2016
2
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
Standards Authorization Request
Informal Comment Period Open through January 20, 2017
Now Available
A 30-day informal comment period for the Project 2013-03 Geomagnetic Disturbance Mitigation
Standards Authorization Request (SAR), is open through 8 p.m. Eastern, Friday, January 20, 2017.
Commenting
Use the electronic form to submit comments on the SAR. If you experience any difficulties using the
electronic form, contact Nasheema Santos. 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, Mark Olson (via email) or at (404)
446-9760.
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 <20##-## Full Name> |
2
Comment Report
Project Name:
2013-03 Geomagnetic Disturbance Mitigation SAR
Comment Period Start Date:
12/16/2016
Comment Period End Date:
1/20/2017
Associated Ballots:
There were 21 sets of responses, including comments from approximately 21 different people from approximately 19 companies
representing 8 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the proposed scope for Project 2013-03 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 (SDT) to consider, if desired.
Organization
Name
ACES Power
Marketing
Duke Energy
Seattle City
Light
Name
Brian Van
Gheem
Colby Bellville
Ginette
Lacasse
Segment(s)
6
1,3,5,6
1,3,4,5,6
Region
NA - Not
Applicable
Group Name
ACES
Standards
Collaborators
FRCC,RF,SERC Duke Energy
WECC
Seattle City
Light Ballot
Group Member
Name
Group
Member
Organization
Group
Member
Segment(s)
1
Group Member
Region
Bob Solomon
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
RF
Karl Kohlrus
Prairie Power, 1,3
Inc.
SERC
Shari Heino
Brazos
1,5
Electric Power
Cooperative,
Inc.
Texas RE
Tara Lightner
Sunflower
1
Electric Power
Corporation
SPP RE
Mark Ringhausen Old Dominion 3,4
Electric
Cooperative
SERC
John Shaver
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Bill Hutchison
Southern
Illinois Power
Cooperative
SERC
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Bill Hutchison
Southern
Illinois Power
Cooperative
1,4
RF
Bill Hutchison
Southern
Illinois Power
Cooperative
1,4
RF
Doug Hils
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Pawel Krupa
Seattle City
Light
1
WECC
1
Body
Southern
Company Southern
Company
Services, Inc.
Marsha Morgan 1,3,5,6
Lower
Michael Shaw
Colorado
River Authority
Northeast
Power
Coordinating
Council
Ruida Shu
SERC
1,5,6
1,2,3,4,5,6,7,10 NPCC
Southern
Company
LCRA
Compliance
Hao Li
Seattle City
Light
4
WECC
Bud (Charles)
Freeman
Seattle City
Light
6
WECC
Mike Haynes
Seattle City
Light
5
WECC
Michael Watkins
Seattle City
Light
1,4
WECC
Faz Kasraie
Seattle City
Light
5
WECC
John Clark
Seattle City
Light
6
WECC
Tuan Tran
Seattle City
Light
3
WECC
Laurrie Hammack Seattle City
Light
3
WECC
Katherine Prewitt
Southern
Company
Services, Inc
1
SERC
Jennifer Sykes
Southern
Company
Generation
and Energy
Marketing
6
SERC
R Scott Moore
Alabama
Power
Company
3
SERC
William Shultz
Southern
Company
Generation
5
SERC
Teresa Cantwell
LCRA
1
Texas RE
Dixie Wells
LCRA
5
Texas RE
Michael Shaw
LCRA
6
Texas RE
Hydro One.
1
NPCC
Northeast
Power
Coordinating
Council
NA - Not
Applicable
NPCC
Randy MacDonald New
Brunswick
Power
2
NPCC
Wayne Sipperly
4
NPCC
RSC no
Paul Malozewski
Dominion and
Guy Zito
OPG
New York
Power
Authority
Midwest
Reliability
Organization
Russel
Mountjoy
10
MRO NSRF
Glen Smith
Entergy
Services
4
NPCC
Brian Robinson
Utility Services 5
NPCC
Bruce Metruck
New York
Power
Authority
6
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Edward Bedder
Orange &
Rockland
Utilities
1
NPCC
David Burke
UI
3
NPCC
Michele Tondalo
UI
1
NPCC
Sylvain Clermont
Hydro Quebec 1
NPCC
Si Truc Phan
Hydro Quebec 2
NPCC
Helen Lainis
IESO
2
NPCC
Laura Mcleod
NB Power
1
NPCC
MIchael Forte
Con Edison
1
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Peter Yost
Con Edison
4
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Greg Campoli
NY-ISO
2
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
Silvia Parada
Mitchell
NextEra
Energy, LLC
4
NPCC
Michael
Schiavone
National Grid
1
NPCC
Michael Jones
National Grid
3
NPCC
3,4,5,6
MRO
Joseph DePoorter Madison Gas
& Electric
Larry Heckert
Alliant Energy 4
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Chuck Lawrence
American
Transmission
1
MRO
Company
Michael Brytowski Great River
Energy
Southwest
Power Pool,
Inc. (RTO)
Shannon
Mickens
2
SPP RE
1,3,5,6
MRO
Jodi Jensen
Western Area 1,6
Power
Administratino
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
1,3,5,6
MRO
Mahmood Safi
Omaha Public 1,3,5,6
Power District
MRO
Brad Parret
Minnesota
Power
1,5
MRO
Terry Harbour
MidAmerican
Energy
Company
1,3
MRO
Tom Breene
Wisconsin
3,5,6
Public Service
MRO
Jeremy Volls
Basin Electric 1
Power Coop
MRO
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
Mike Morrow
Midcontinent
Independent
System
Operator
2
MRO
2
SPP RE
James Nail
Independence 3
Power and
Light
SPP RE
Allan George
Sunflower
1
Electric Power
Corp
SPP RE
Jonathan Hayes
Southwest
Power Pool
Inc.
SPP RE
SPP
Shannon Mickens Southwest
Standards
Power Pool
Inc.
Review Group
2
1. Do you agree with the proposed scope for Project 2013-03 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.
David Jendras - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
Comment
The proposed revision to standard TPL-007-1 to address localized peaks in GMD events and not rely solely on the spatially-averaged data has the
potential to impact much more of the transmission system and many more EHV Y-connected transformers than we had previously estimated. It is
unknown at this time how the SDT will modify the standard to include this FERC mandated revision, but this would be a major concern for TOs.
It appears that Ameren as a TO will be required to install GIC monitoring equipment and magnetometers, collect data from these devices, and make the
data available to those that have a need for the information. Details are still to be determined by the SDT, with the cost to install such equipment and
maintain data is unknown.
Although the FERC directive allows for TOs to apply for an exemption to collect necessary GIC monitoring data, exemption criteria has not been
proposed to determine if the exemption would or would not be allowed in a particular case. Regardless, because of our location in the Midwest and
because of the number of 345 kV lines and EHV Y-connected transformers connected to the Ameren system, it is unlikely that Ameren would be
allowed an exemption from installing monitoring equipment and collecting the GIC data, regardless of our southerly location in relation to the
geomagnetic north pole.
Due to the fact that FERC is mandating these modifications, we are concerned that input from industry on the drafting of the revised standard would be
given minimal consideration.
Likes
0
Dislikes
0
Response
Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
The NSRF agrees with the proposed scope for Project 2013-03 SAR but would like to make several suggestions that will benefit the reliable operation of
the BES. If the standard drafting team plans to incorporate real-time reliability monitoring and analysis to satisfy the GMD monitoring requirements, we
suggest the SDT add Transmission Operator (TOP) as an applicable Reliability Function in the SAR.
Rationale
FERC gives NERC the option to incorporate the GMD monitoring data collection in another reliability standard. The TOP is the responsible entity to
complete real-time reliability monitoring.
“NERC may also propose to incorporate the GIC monitoring and magnetometer data collection requirements in a different Reliability Standard (e.g.,
real-time reliability monitoring and analysis capabilities as part of the TOP Reliability Standards).” (FERC Order 830, P.91) .
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA would like to know if the model validation encompasses equipment and system models for accurate GIC current determination (like transformer
behavior). BPA would also like to know if the model validation encompass hysteresis curves for VAR consumption determination? BPA believes the
model should contain both.
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Yes
Document Name
Comment
Our subject matter experts do not believe that collected data should be available to the public. Or clearly define what is meant by "publicly available"
and what specifically can be available.
Likes
Dislikes
0
0
Response
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Comment
(1) We believe the proposed scope captures the directives identified in FERC Order No. 830. However, we believe several references to the FERC
Order are taken out of context, and should be removed from the SAR’s Detailed Description Section. The Commission wants GIC monitoring and
magnetometer data to be gathered through collaboration with academia and government agencies. The reference to include “…any device that must
be added…”could misdirect the SDT from the Commission’s intentions. We recommend the removal of this particular reference to limit the scope of
data collection.
(2) We feel the FERC directive references should be mapped to existing requirements to identify proposed changes. For example, we recommend
adding a reference to Requirement R3 when listing the directives associated with Benchmark Events. Likewise, when listing directives for Transformer
Thermal Impact Assessment or Corrective Action Plans, Requirement R6 and Requirement R7 should be included as references, respectively.
(3) We question the addition of a reference to move the data collection of GIC monitoring and magnetometer data to a different Reliability Standard.
We feel this inclusion opens the door to a Commission suggestion to incorporate data collection as part of real-time reliability monitoring and analysis
and relocated to the TOP Reliability Standards. We feel that if such data was required for real-time operations, it likely would have been incorporated in
NERC Reliability Standard EOP-010-1, as part of emergency Geomagnetic Disturbance Operations. We recommend the removal of this reference to
focus the scope of this project on TPL-007.
(4) The SAR briefly lists the development of an implementation plan, although does not elaborate on what may change within the SAR’s Detailed
Description Section. While the current five year implementation plan takes effect starting July 2017, we feel a significant portion of the implementation
plan will pass by the time the Commission approves the work of this SDT. We recommend the addition of a reference within the SAR’s Detailed
Description Section to incorporate modifications to the implementation plan that accounts for the transition away from the current implementation plane.
We believe the transition period should not be less than 18 months to accommodate an impacted entity’s effort to implement modeling and software
changes, additional resource procurements, and quality assurance of assessments.
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,10 - NPCC, Group Name RSC no Dominion and OPG
Answer
Yes
Document Name
Comment
NPCC RSC support the proposed scope for Project 2013-03.
Likes
Dislikes
0
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jeffrey DePriest - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Tho Tran - Oncor Electric Delivery - 1 - Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Thomas Foltz - AEP - 3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
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
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Teresa Cantwell - Lower Colorado River Authority - 1,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Michael Shaw - Lower Colorado River Authority - 1,5,6, Group Name LCRA Compliance
Answer
Document Name
Comment
Likes
0
Dislikes
Response
0
2013-03_GMD_SAR_Unofficial_Comment_Form_121516.docx
2. Provide any additional comments for the Standards Drafting Team (SDT) to consider, if desired.
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
(1) We believe the SDT should collaborate its activities with existing industry technical groups, including the NERC Geomagnetic Disturbance Task
Force, when designing GIC monitoring and magnetometer data collection criteria. We propose limiting the focus of this SAR to GIC monitoring and
magnetometer data collection, and allow NERC and these other groups to address how such data will be shared publicly. We fear the SDT’s
involvement with the distribution of data could lead to unnecessarydevelopment of new Reliability Standards for currently unregistered entities and
functions.
(2) We thank you for this opportunity to provide these comments.
Likes
0
Dislikes
0
Response
Teresa Cantwell - Lower Colorado River Authority - 1,5,6
Answer
Document Name
Comment
The approach related to the GMD benchmark definition and transformer thermal impact assessment needs to balance ease of implementation with the
quality of results.
A methodology similar to that employed in PRC-002 should be utilized to limit the required number of installations of monitoring data (e.g. based on
short circuit MVA or some other parameter). Not every TO should be required to install monitoring data. This may be better accomplished by rolling the
monitoring requirement into another standard (e.g. PRC-002).
NERC should consider extensions of time for CAPs and/or hardware installation on a case-by-case basis.
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE made the following observations:
•
Paragraph 91 in Order No. 830 discusses the ability for a Transmission Owner to apply for an exemption. Texas RE is concerned if the
responsible entity determined in R1 is allowed to grant exemptions, many entities that are registered as a TP and TO will be able to grant itself
an exemption. Texas RE recommends determining who is responsible for granting exemptions, since Order No. 830 does not specify.
•
The “Industry Need” section includes details about NERC making GMD-related data publicly available, but “Detailed Description” section does
not.
•
In the “Collection of GMD Data” section, the SAR states that “Each responsible entity that is a transmission owner should be required to collect
necessary GIC monitoring data.” However, TPL-007-1 R1 currently defines a “responsible entity” as either a TP or a PC. When updating the
Standard, the SDT should avoid using “responsible entity” when referencing a TO.
•
Texas RE recommends emphasizing sufficient and appropriate compliance documentation, regarding an “equally efficient and effective
alternative”. An entity would be required to demonstrate efficiency and effectiveness. For the data submittal portion, there needs to be care in
addressing timing as the directive included historical and new data. There is no discussion of data requirements, per se, and the content,
format, or timing associated with the data.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
After reviewing the transcript associated with the Level 2 Appeal of Foundation For Resilient Societies, INC. in reference to TPL-007-1, we suggest the
drafting team review and use this document as guidance throughout their modification process to the Standard. In our review, we found some
similarities of concerns shared by both The Foundation for Resilient Societies, INC and FERC Order 830 such as, transformer thermal impact
assessments as well as data collection and how that information would be made publicly available.
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
Thank you for seeking our input in advance.
Likes
0
Dislikes
0
Response
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Because commercially available models and tools do not currently exist for performing transformer thermal impact assessments, we ask the SDT to
continue considering suitable alternates (e.g., look up tables, development of flowcharts or processes).
Also, we ask the SDT to provide clarification of the event included in Table 1 - Steady State Planning Events. In particular, with regards to protection
system misoperation due to harmonics during a GMD event, please provide clarification as to what is expected. Will this require that large scale
harmonic penetration studies be performed in order to analyze potential impact of half-cycle saturation generated harmonics on system protection
and/or equipment controls? Or will engineering assessments that identify credible scenarios be sufficient?
SDT to consider that the procurement and installation of instrument transformers for the collection of GIC monitoring and magnetometer data takes
months to implement. SDT to consider realistic timelines for implementation, as well as providing technical guidance for implementation of GIC
measurement devices.
We ask the SDT to provide additional clarification on R2. In particular, SDT to elaborate on "maintaining System models and GIC System Models." Is R2
referring to gathering and maintaining dc and ac models (e.g., substation dc resitances, dc network data) of the system under study? Does it require
having to complete a GIC analysis by R2 deadline, so that GIC system models can be produced and maintained? Please provide clarification.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
The change in deadlines for mitigation of GMD events would not be a concern in Ameren's case. Ameren is not interested in installing blocking devices
to Y-connected EHV transformers. Therefore, operational solutions will provide the likely mitigations.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA would like to know how the Standard Drafting Team envisions collecting the data to perform the studies. If there is no regional data collection
effort similar to MOD-032, then how is it envisioned that accurate GIC studies to determine DC currents will be run? BPA believes a documented
process needs to be created WECC wide (or nationally). BPA envisions the data collection included with MOD-032 to be collected every 5 years (or
according to study schedule with version 2 of TPL-007). BPA’s experience is that most entities are not willing to take on extra work if they do not have
to.
Likes
0
Dislikes
0
Response
Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
Comment
PacifiCorp supports the proposal to incorporate the GIC monitoring and magnetometer data collection requirements in a different Reliability Standard.
This separation would allow more attention to the specific upgrades already outlined in the SAR.
Likes
0
Dislikes
0
Response
Jeffrey DePriest - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Document Name
Comment
Please consider an approach where GIC monitor locations are determined on a regional basis in order to obtain the most value from each installation
and insure that all areas are covered appropriately. An individual GO/TO may not have the information needed to properly place equipment. Also,
providing monitoring equipment specifications would insure that manufacturers would design, and entities would install, capable monitors that will
provide reliable data.
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Document Name
Comment
Please consider an approach where GIC monitor locations are determined on a regional basis in order to obtain the most value from each installation
and insure that all areas are covered appropriately. An individual GO/TO may not have the information needed to properly place equipment. Also,
providing monitoring equipment specifications would insure that manufacturers would design, and entities would install, capable monitors that will
provide reliable data.
Likes
0
Dislikes
0
Response
Michael Shaw - Lower Colorado River Authority - 1,5,6, Group Name LCRA Compliance
Answer
Document Name
2013-03_GMD_SAR_Unofficial_Comment_Form_121516.docx
Comment
Likes
0
Dislikes
Response
0
Consideration of Comments
Project Name:
2013-03 Geomagnetic Disturbance Mitigation SAR
Comment Period Start
Date:
12/16/2016
Comment Period End Date: 1/20/2017
There were 21 sets of responses, including comments from approximately 21 different people from approximately 19
companies representing 8 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 Director of
Standards Development, Steve Noess (via email) or at (404) 446‐9691.
Questions
1. Do you agree with the proposed scope for Project 2013-03 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 (SDT) to consider, if desired.
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 | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
2
Organization
Name
Name
ACES Power Brian Van
Marketing
Gheem
Segment(s)
6
Region
NA - Not
Applicable
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
Group Name
Group
Member Name
ACES
Bob Solomon
Standards
Collaborators
Group
Group
Member
Member
Organization Segment(s)
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
1
Group Member
Region
RF
Karl Kohlrus
Prairie Power, 1,3
Inc.
SERC
Shari Heino
Brazos Electric 1,5
Power
Cooperative,
Inc.
Texas RE
Tara Lightner
Sunflower
1
Electric Power
Corporation
SPP RE
Mark
Ringhausen
Old Dominion 3,4
Electric
Cooperative
SERC
John Shaver
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Bill Hutchison
Southern
1
Illinois Power
Cooperative
SERC
3
Duke Energy Colby
Bellville
Seattle City
Light
Ginette
Lacasse
1,3,5,6
Scott Brame
North Carolina 3,4,5
Electric
Membership
Corporation
SERC
Bill Hutchison
Southern
1,4
Illinois Power
Cooperative
RF
Bill Hutchison
Southern
1,4
Illinois Power
Cooperative
RF
Duke Energy
1
RF
Duke Energy
3
FRCC
Dale Goodwine Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Pawel Krupa
Seattle City
Light
1
WECC
Hao Li
Seattle City
Light
4
WECC
Bud (Charles)
Freeman
Seattle City
Light
6
WECC
Mike Haynes
Seattle City
Light
5
WECC
Michael
Watkins
Seattle City
Light
1,4
WECC
Faz Kasraie
Seattle City
Light
5
WECC
FRCC,RF,SERC Duke Energy Doug Hils
Lee Schuster
1,3,4,5,6
WECC
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
Seattle City
Light Ballot
Body
4
Southern
Marsha
Company - Morgan
Southern
Company
Services, Inc.
Lower
Colorado
River
Authority
Michael
Shaw
Northeast
Ruida Shu
Power
Coordinating
Council
1,3,5,6
SERC
1,5,6
1,2,3,4,5,6,7,10 NPCC
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
Southern
Company
LCRA
Compliance
RSC no
Dominion
and OPG
John Clark
Seattle City
Light
6
WECC
Tuan Tran
Seattle City
Light
3
WECC
Laurrie
Hammack
Seattle City
Light
3
WECC
Katherine
Prewitt
Southern
Company
Services, Inc
1
SERC
Jennifer Sykes Southern
Company
Generation
and Energy
Marketing
6
SERC
R Scott Moore Alabama
Power
Company
3
SERC
William Shultz Southern
Company
Generation
5
SERC
Teresa
Cantwell
LCRA
1
Texas RE
Dixie Wells
LCRA
5
Texas RE
Michael Shaw
LCRA
6
Texas RE
Paul
Malozewski
Hydro One.
1
NPCC
Guy Zito
Northeast
Power
NA - Not
Applicable
NPCC
5
Coordinating
Council
Randy
MacDonald
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
New
Brunswick
Power
2
NPCC
Wayne Sipperly New York
Power
Authority
4
NPCC
Glen Smith
4
NPCC
Brian Robinson Utility Services 5
NPCC
Bruce Metruck New York
Power
Authority
6
NPCC
Alan Adamson New York
State
Reliability
Council
7
NPCC
Edward Bedder Orange &
Rockland
Utilities
1
NPCC
David Burke
UI
3
NPCC
Michele
Tondalo
UI
1
NPCC
Sylvain
Clermont
Hydro Quebec 1
NPCC
Si Truc Phan
Hydro Quebec 2
NPCC
Entergy
Services
6
Midwest
Russel
Reliability
Mountjoy
Organization
10
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
MRO NSRF
Helen Lainis
IESO
2
NPCC
Laura Mcleod
NB Power
1
NPCC
MIchael Forte
Con Edison
1
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Peter Yost
Con Edison
4
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Greg Campoli
NY-ISO
2
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
Silvia Parada
Mitchell
NextEra
Energy, LLC
4
NPCC
Michael
Schiavone
National Grid 1
NPCC
Michael Jones National Grid 3
NPCC
Joseph
DePoorter
Madison Gas
& Electric
MRO
Larry Heckert
Alliant Energy 4
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Chuck
Lawrence
American
Transmission
Company
1
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
3,4,5,6
7
Southwest Shannon
Power Pool, Mickens
Inc. (RTO)
2
SPP RE
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
SPP
Standards
Jodi Jensen
Western Area 1,6
Power
Administratino
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
1,3,5,6
MRO
Mahmood Safi Omaha Public 1,3,5,6
Power District
MRO
Brad Parret
1,5
MRO
Terry Harbour MidAmerican 1,3
Energy
Company
MRO
Tom Breene
Wisconsin
3,5,6
Public Service
MRO
Jeremy Volls
Basin Electric 1
Power Coop
MRO
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
Mike Morrow
Midcontinent 2
Independent
System
Operator
MRO
Shannon
Mickens
Southwest
Power Pool
Inc.
SPP RE
Minnesota
Power
2
8
Review
Group
James Nail
Independence 3
Power and
Light
SPP RE
Allan George
Sunflower
1
Electric Power
Corp
SPP RE
Jonathan Hayes Southwest
Power Pool
Inc.
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
2
SPP RE
9
1. Do you agree with the proposed scope for Project 2013-03 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.
David Jendras - Ameren - Ameren Services - 1,3,6
Answer
No
Document Name
Comment
The proposed revision to standard TPL-007-1 to address localized peaks in GMD events and not rely solely on the spatially-averaged data has
the potential to impact much more of the transmission system and many more EHV Y-connected transformers than we had previously
estimated. It is unknown at this time how the SDT will modify the standard to include this FERC mandated revision, but this would be a major
concern for TOs.
It appears that Ameren as a TO will be required to install GIC monitoring equipment and magnetometers, collect data from these devices, and
make the data available to those that have a need for the information. Details are still to be determined by the SDT, with the cost to install
such equipment and maintain data is unknown.
Although the FERC directive allows for TOs to apply for an exemption to collect necessary GIC monitoring data, exemption criteria has not
been proposed to determine if the exemption would or would not be allowed in a particular case. Regardless, because of our location in the
Midwest and because of the number of 345 kV lines and EHV Y-connected transformers connected to the Ameren system, it is unlikely that
Ameren would be allowed an exemption from installing monitoring equipment and collecting the GIC data, regardless of our southerly
location in relation to the geomagnetic north pole.
Due to the fact that FERC is mandating these modifications, we are concerned that input from industry on the drafting of the revised standard
would be given minimal consideration.
Likes
Dislikes
0
0
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
10
Response. Thank you for your comments. In order to address the FERC Order No. 830 directives, the SDT will consider ways to incorporate
localized peak events into the existing GMD benchmark. It is too soon to know how the benchmark will change and what the impact on the
industry will be. Regarding the installation of GIC monitors and magnetometers the SDT intends to coordinate technical details with the NERC
GMD Task Force. There is significant industry experience on the SDT, so any requirements that are added to the standard will be discussed
within the SDT and with the NERC GMD Task Force. Stakeholder input will be considered by the SDT throughout the standard development
process.
Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
The NSRF agrees with the proposed scope for Project 2013-03 SAR but would like to make several suggestions that will benefit the reliable
operation of the BES. If the standard drafting team plans to incorporate real-time reliability monitoring and analysis to satisfy the GMD
monitoring requirements, we suggest the SDT add Transmission Operator (TOP) as an applicable Reliability Function in the SAR.
Rationale
FERC gives NERC the option to incorporate the GMD monitoring data collection in another reliability standard. The TOP is the responsible
entity to complete real-time reliability monitoring.
“NERC may also propose to incorporate the GIC monitoring and magnetometer data collection requirements in a different Reliability Standard
(e.g., real-time reliability monitoring and analysis capabilities as part of the TOP Reliability Standards).” (FERC Order 830, P.91) .
Likes
Dislikes
0
0
Response. Thank you for your comments. Order No. 830 directs NERC to address the collection of data from GIC detectors and
magnetometers for the purpose of aiding in the validation of models used to facilitate the calculations required in TPL-007. It does not
require real time data collection, but that doesn’t limit entities from collecting real time data in support of system operations. If an entity’s
Consideration of Comments | Standard Authorization Request
2013-03 Geomagnetic Disturbance Mitigation | March 16, 2017
11
operating procedure requires real time data collection, then that process would be documented in procedures under EOP-010 and the TOP
would be an applicable entity.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA would like to know if the model validation encompasses equipment and system models for accurate GIC current determination (like
transformer behavior). BPA would also like to know if the model validation encompass hysteresis curves for VAR consumption
determination? BPA believes the model should contain both.
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Response. Thank you for your comments. Order No. 830 is not prescriptive regarding what kind of models would be validated using GIC
and/or geomagnetic field measurements. The SDT believes the requirements should be application-neutral.
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Yes
Document Name
Comment
Our subject matter experts do not believe that collected data should be available to the public. Or clearly define what is meant by "publicly
available" and what specifically can be available.
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Response. Thank you for your comment. Order No. 830 is clear in directing NERC to require entities to collect GIC and magnetometer data,
and for NERC to make the data publically available. The details of such a program are yet to be worked out, but will include discussions
among the SDT, the NERC GMD Task Force, and NERC. In Order No. 830, FERC indicated that they were not persuaded by arguments in the
record for TPL-007-1 that this data should be treated as confidential, but that entities could seek confidential treatment of their data from
NERC (P 94-95). Accordingly, NERC's data collection process developed to meet Order No. 830 is expected to provide entities with the means
for identifying some or all data that the entity believes should be treated as confidential.
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Comment
(1) We believe the proposed scope captures the directives identified in FERC Order No. 830. However, we believe several references to the
FERC Order are taken out of context, and should be removed from the SAR’s Detailed Description Section. The Commission wants GIC
monitoring and magnetometer data to be gathered through collaboration with academia and government agencies. The reference to include
“…any device that must be added…”could misdirect the SDT from the Commission’s intentions. We recommend the removal of this particular
reference to limit the scope of data collection.
(2) We feel the FERC directive references should be mapped to existing requirements to identify proposed changes. For example, we
recommend adding a reference to Requirement R3 when listing the directives associated with Benchmark Events. Likewise, when listing
directives for Transformer Thermal Impact Assessment or Corrective Action Plans, Requirement R6 and Requirement R7 should be included
as references, respectively.
(3) We question the addition of a reference to move the data collection of GIC monitoring and magnetometer data to a different Reliability
Standard. We feel this inclusion opens the door to a Commission suggestion to incorporate data collection as part of real-time reliability
monitoring and analysis and relocated to the TOP Reliability Standards. We feel that if such data was required for real-time operations, it
likely would have been incorporated in NERC Reliability Standard EOP-010-1, as part of emergency Geomagnetic Disturbance Operations. We
recommend the removal of this reference to focus the scope of this project on TPL-007.
(4) The SAR briefly lists the development of an implementation plan, although does not elaborate on what may change within the SAR’s
Detailed Description Section. While the current five year implementation plan takes effect starting July 2017, we feel a significant portion of
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the implementation plan will pass by the time the Commission approves the work of this SDT. We recommend the addition of a reference
within the SAR’s Detailed Description Section to incorporate modifications to the implementation plan that accounts for the transition away
from the current implementation plane. We believe the transition period should not be less than 18 months to accommodate an impacted
entity’s effort to implement modeling and software changes, additional resource procurements, and quality assurance of assessments.
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Response. Thank you for your comments.
(1) The FERC order discusses the option of collaborating with academia and government agencies for the collection of data, but that is not
the only option provided in the order. It is understood that additional GIC detectors and magnetometers may be required and the SAR
accounts for this additional option.
(2) References to the existing standard requirements will be added to the SAR as minor editorial changes.
(3) The SAR statement on the possibility of placing data collection requirements in another standard is from the FERC order. (paragraph 91)
(4) It is too soon to know what additional requirements may be placed on applicable entities as a result of modifications to the existing
standard. Accordingly, any statements about changes to the implementation plan are premature. The SDT believes the SAR as written
provides the necessary project scope for developing an implementation plan.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,10 - NPCC, Group Name RSC no Dominion and OPG
Answer
Yes
Document Name
Comment
NPCC RSC support the proposed scope for Project 2013-03.
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0
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Response. Thank you for your comment.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Yes
Document Name
Comment
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0
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0
Response
Jeffrey DePriest - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Tho Tran - Oncor Electric Delivery - 1 - Texas RE
Answer
Yes
Document Name
Comment
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Likes
0
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0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6
Answer
Yes
Document Name
Comment
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0
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0
Response
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
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0
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0
Response
Thomas Foltz - AEP - 3,5
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Answer
Yes
Document Name
Comment
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0
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0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Yes
Document Name
Comment
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0
0
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Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
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0
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0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
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0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Comment
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Likes
0
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0
Response
Teresa Cantwell - Lower Colorado River Authority - 1,5,6
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Michael Shaw - Lower Colorado River Authority - 1,5,6, Group Name LCRA Compliance
Answer
Document Name
Comment
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0
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0
Response
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2. Provide any additional comments for the Standards Drafting Team (SDT) to consider, if desired.
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
(1) We believe the SDT should collaborate its activities with existing industry technical groups, including the NERC Geomagnetic Disturbance
Task Force, when designing GIC monitoring and magnetometer data collection criteria. We propose limiting the focus of this SAR to GIC
monitoring and magnetometer data collection, and allow NERC and these other groups to address how such data will be shared publicly. We
fear the SDT’s involvement with the distribution of data could lead to unnecessary development of new Reliability Standards for currently
unregistered entities and functions.
(2) We thank you for this opportunity to provide these comments.
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Response. Thank you for your comment. The SDT intends to collaborate its standards development activities with the NERC GMD Task Force,
and where appropriate other industry technical groups. The SDT agrees that NERC and other technical groups should address issues with the
public availability of collected data. The SDT is focused on developing requirements for the collection of data as specified in Order No. 830 P 88
and P 91. The SDT has clarified this in the project SAR. The process for the distribution of that data will likely be addressed outside of the
revised standard.
Teresa Cantwell - Lower Colorado River Authority - 1,5,6
Answer
Document Name
Consideration of Comments | Standard Authorization Request
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Comment
The approach related to the GMD benchmark definition and transformer thermal impact assessment needs to balance ease of implementation
with the quality of results.
A methodology similar to that employed in PRC-002 should be utilized to limit the required number of installations of monitoring data (e.g.
based on short circuit MVA or some other parameter). Not every TO should be required to install monitoring data. This may be better
accomplished by rolling the monitoring requirement into another standard (e.g. PRC-002).
NERC should consider extensions of time for CAPs and/or hardware installation on a case-by-case basis.
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Response. Thank you for your comment. The SDT will consider these inputs during standard development. The SDT believes that that there
is a balance between ease of implementation and a conservative approach to potential transformer impact by means of the transformer
thermal screening criteria.
The SDT will work in conjunction with the NERC GMD Task Force and other industry technical groups in the development of criteria for number
and/or location of monitoring equipment.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE made the following observations:
•
Paragraph 91 in Order No. 830 discusses the ability for a Transmission Owner to apply for an exemption. Texas RE is concerned if the
responsible entity determined in R1 is allowed to grant exemptions, many entities that are registered as a TP and TO will be able to
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grant itself an exemption. Texas RE recommends determining who is responsible for granting exemptions, since Order No. 830 does
not specify.
•
The “Industry Need” section includes details about NERC making GMD-related data publicly available, but “Detailed Description”
section does not.
•
In the “Collection of GMD Data” section, the SAR states that “Each responsible entity that is a transmission owner should be required
to collect necessary GIC monitoring data.” However, TPL-007-1 R1 currently defines a “responsible entity” as either a TP or a PC. When
updating the Standard, the SDT should avoid using “responsible entity” when referencing a TO.
•
Texas RE recommends emphasizing sufficient and appropriate compliance documentation, regarding an “equally efficient and effective
alternative”. An entity would be required to demonstrate efficiency and effectiveness. For the data submittal portion, there needs to
be care in addressing timing as the directive included historical and new data. There is no discussion of data requirements, per se, and
the content, format, or timing associated with the data.
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Response. Thank you for your comments.
Order No. 830 states that entities should be able to apply for exemption from data collection requirements if an entity “demonstrates that no
or little value would be added to planning and operations.” The order provides flexibility for the SDT to establish the process and criteria for
requesting and approving such exemptions. The SDT will be discussing the exemption process as part of its work on the revised standard.
The detailed description section of the SAR contains excerpts from the FERC order with a reference to the applicable paragraph in the order.
The SDT believes that it is sufficiently clear that the intent is to make the data publically available
The SDT will make every attempt to provide clarity as to the applicability of the requirements of the standard and will minimize the use of the
term “responsible entity”.
The requirements for the collection and distribution of GIC detector and magnetometer data will be developed by the SDT. The FERC order
does require both historical and new data to be provided, however historical data will be collected by NERC via a Rules of Procedure Section
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1600 data request (not in scope for the standards project). The SDT does not view the Order No. 830 phrase "equally efficient and effective"
to apply to compliance documentation.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
After reviewing the transcript associated with the Level 2 Appeal of Foundation For Resilient Societies, INC. in reference to TPL-007-1, we
suggest the drafting team review and use this document as guidance throughout their modification process to the Standard. In our review, we
found some similarities of concerns shared by both The Foundation for Resilient Societies, INC and FERC Order 830 such as, transformer
thermal impact assessments as well as data collection and how that information would be made publicly available.
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Response. Thank you for your comments. The SDT is aware of Level 2 Appeal transcript. The SDT responded to comments raised by the
Foundation for Resilient Societies during development of TPL-007-1.
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
Thank you for seeking our input in advance.
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Response
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
Because commercially available models and tools do not currently exist for performing transformer thermal impact assessments, we ask the
SDT to continue considering suitable alternates (e.g., look up tables, development of flowcharts or processes).
Also, we ask the SDT to provide clarification of the event included in Table 1 - Steady State Planning Events. In particular, with regards to
protection system misoperation due to harmonics during a GMD event, please provide clarification as to what is expected. Will this require
that large scale harmonic penetration studies be performed in order to analyze potential impact of half-cycle saturation generated harmonics
on system protection and/or equipment controls? Or will engineering assessments that identify credible scenarios be sufficient?
SDT to consider that the procurement and installation of instrument transformers for the collection of GIC monitoring and magnetometer data
takes months to implement. SDT to consider realistic timelines for implementation, as well as providing technical guidance for implementation
of GIC measurement devices.
We ask the SDT to provide additional clarification on R2. In particular, SDT to elaborate on "maintaining System models and GIC System
Models." Is R2 referring to gathering and maintaining dc and ac models (e.g., substation dc resistances, dc network data) of the system under
study? Does it require having to complete a GIC analysis by R2 deadline, so that GIC system models can be produced and maintained? Please
provide clarification.
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Response. Thank you for your comments. The SDT has provided alternatives for conducting the transformer thermal impact assessments in
the original standard and intends to continue in that mode for any modifications that may be necessary to address the FERC directives.
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The SDT recognizes that detailed harmonic analyses may be beyond the capability of many applicable entities. As stated in the development of
TPL-007-1, reasonable engineering judgment can be exercised to identify protection equipment that may be vulnerable to misoperation in the
Benchmark GMD event and therefore, should be placed out of service in the power flow analysis. (See Project 2013-03 Consideration of
Comments dated December 5, 2014, P. 16, P. 48)
To the degree that additional GIC detectors and/or magnetometers are necessary to be installed, the SDT will address the timeframe to install
such devices in the implementation plan.
The intent of requirement R2 in TPL-007-1 is to require entities to maintain models necessary to perform the required analysis (both ac models
for the network analysis and dc models for the GIC calculation). Requirement R2 does not specify that GIC calculations must be completed.
David Jendras - Ameren - Ameren Services - 1,3,6
Answer
Document Name
Comment
The change in deadlines for mitigation of GMD events would not be a concern in Ameren's case. Ameren is not interested in installing blocking
devices to Y-connected EHV transformers. Therefore, operational solutions will provide the likely mitigations.
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Response Thank you for the comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
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BPA would like to know how the Standard Drafting Team envisions collecting the data to perform the studies. If there is no regional data
collection effort similar to MOD-032, then how is it envisioned that accurate GIC studies to determine DC currents will be run? BPA believes a
documented process needs to be created WECC wide (or nationally). BPA envisions the data collection included with MOD-032 to be collected
every 5 years (or according to study schedule with version 2 of TPL-007). BPA’s experience is that most entities are not willing to take on extra
work if they do not have to.
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Response. Thank you for your comment. As noted in development of TPL-007-1, the standard provides flexibility for various approaches to
collecting the necessary data for GMD Vulnerability Assessments, including the use of regional planning groups. (See Project 2013-03
Consideration of Comments dated October 28, 2014, P. 23). The whitepapers associated with the development of TPL-007-1 address the
process of performing the GIC calculations.
Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment
None
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0
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0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
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Answer
Document Name
Comment
PacifiCorp supports the proposal to incorporate the GIC monitoring and magnetometer data collection requirements in a different Reliability
Standard. This separation would allow more attention to the specific upgrades already outlined in the SAR.
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0
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0
Response. Thank you for your comment. The SDT will develop the GIC monitoring and magnetometer data collection requirements and then
determine the most appropriate location for those requirements.
Jeffrey DePriest - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Document Name
Comment
Please consider an approach where GIC monitor locations are determined on a regional basis in order to obtain the most value from each
installation and insure that all areas are covered appropriately. An individual GO/TO may not have the information needed to properly place
equipment. Also, providing monitoring equipment specifications would insure that manufacturers would design, and entities would install,
capable monitors that will provide reliable data.
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0
0
Response. The SDT will develop the GIC monitoring and magnetometer data collection requirements and determine the most appropriate
location for those requirements. The SDT will work with the NERC GMD Task Force on the issue of equipment specifications.
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Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Document Name
Comment
Please consider an approach where GIC monitor locations are determined on a regional basis in order to obtain the most value from each
installation and insure that all areas are covered appropriately. An individual GO/TO may not have the information needed to properly place
equipment. Also, providing monitoring equipment specifications would insure that manufacturers would design, and entities would install,
capable monitors that will provide reliable data.
Likes
0
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0
Response. The SDT will develop the GIC monitoring and magnetometer data collection requirements and determine the most appropriate
location for those requirements. The SDT will work with the NERC GMD Task Force on the issue of equipment specifications
Michael Shaw - Lower Colorado River Authority - 1,5,6, Group Name LCRA Compliance
Answer
Document Name
Comment
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0
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Response
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Standards Authorization Request Form
When completed, email this form to:
sarcomm@nerc.com
NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
Modifications to Geomagnetic Disturbance Standards
Date Submitted:
February 23, 2017
SAR Requester Information
Name:
Frank Koza
Organization:
PJM Interconnection / Project 2013-03 SDT Chair
Telephone:
610-666-4228
E-mail:
frank.koza@pjm.com
SAR Type (Check as many as applicable)
New Standard
Withdrawal of existing Standard
Revision to existing Standard
Urgent Action
SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The goal of this project is to address the Federal Energy Regulatory Commission (Commission) directives
contained in Order No. 830 by modifying TPL-007-1 - Transmission System Planned Performance for
Geomagnetic Disturbance Events and the benchmark GMD event used in GMD Vulnerability
Assessments or by developing an equally efficient and effective alternative.
Industry Need (What is the industry problem this request is trying to solve?):
On September 22, 2016, the Commission issued Order No. 830 approving TPL-007-1. In the order, the
Commission directed NERC to develop certain modifications to the Standard, including:
•
•
Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact
assessments;
SAR Information
•
•
Require collection of GMD-related data, which NERC should make available to the public;
and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
The Commission established a deadline of 18 months from the effective date of Order No. 830 for
completing the revisions, which is May 29, 2018.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The Standards Drafting Team (SDT) shall develop modifications to TPL-007-1 and the benchmark GMD
event that address Commission directives from Order No. 830. The work will include development of
Violation Risk Factors, Violation Severity Levels, and an Implementation Plan for the modified standards
within the deadline established by the Commission in Order No. 830.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDT shall address each of the Order No. 830 directives by developing modifications to requirements
in TPL-007-1 and related material, or the SDT shall develop an equally efficient and effective alternative.
To address concerns identified in Order No. 830, the Commission directed the following:
Benchmark GMD Event (TPL-007-1 Attachment 1 and related requirements)
• [T]he Commission, as proposed in the NOPR, directs NERC to develop revisions to the benchmark
GMD event definition so that the reference peak geoelectric field amplitude component is not
based solely on spatially-averaged data.(P.44)
• Without prejudging how NERC proposes to address the Commission’s directive, NERC’s response
to this directive should satisfy the NOPR’s concern that reliance on spatially-averaged data alone
does not address localized peaks that could potentially affect the reliable operation of the BulkPower System. (P.47)
Transformer Thermal Impact Assessment (TPL-007-1 Requirement R6)
• Consistent with our determination above regarding the reference peak geoelectric field
amplitude value, the Commission directs NERC to revise Requirement R6 to require registered
entities to apply spatially averaged and non-spatially averaged peak geoelectric field values, or
some equally efficient and effective alternative, when conducting thermal impact assessments.
(P.65)
Collection of GMD Data
• The Commission … adopts the NOPR proposal in relevant part and directs NERC to develop
revisions to Reliability Standard TPL-007-1 to require responsible entities to collect GIC
monitoring and magnetometer data as necessary to enable model validation and situational
awareness, including from any devices that must be added to meet this need. The NERC standard
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2
SAR Information
•
•
drafting team should address the criteria for collecting GIC monitoring and magnetometer data...
and provide registered entities with sufficient guidance in terms of defining the data that must be
collected.... (P.88)
Each responsible entity that is a transmission owner should be required to collect necessary GIC
monitoring data. However, a transmission owner should be able to apply for an exemption from
the GIC monitoring data collection requirement if it demonstrates that little or no value would be
added to planning and operations. (P.91)
NERC may also propose to incorporate the GIC monitoring and magnetometer data collection
requirements in a different Reliability Standard....(P.91)
Deadlines for Corrective Action Plans and Mitigations (TPL-007-1 Requirement R7)
• The Commission directs NERC to modify Reliability Standard TPL-007-1 to include a deadline of
one year from the completion of the GMD Vulnerability Assessments to complete the
development of corrective action plans. (P.101)
• The Commission also directs NERC to modify Reliability Standard TPL-007-1 to include a two-year
deadline after the development of the corrective action plan to complete the implementation of
non-hardware mitigation and four-year deadline to complete hardware mitigation…. The
Commission agrees that NERC should consider extensions of time on a case-by-case basis. (P.102)
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Project 2013-03 Geomagnetic Disturbance Mitigation
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Reliability Functions
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and Reactive Power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all 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.
Project 2013-03 Geomagnetic Disturbance Mitigation
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4
Reliability and Market Interface Principles
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.
Does the proposed Standard 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.
Enter
(yes/no)
YES
YES
YES
YES
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Project 2013-03 Geomagnetic Disturbance Mitigation
February 23, 2017
Explanation
5
Regional Variances
Region
Explanation
FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC
Project 2013-03 Geomagnetic Disturbance Mitigation
February 23, 2017
6
Standards Authorization Request Form
When completed, email this form to:
sarcomm@nerc.com
NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
Modifications to Geomagnetic Disturbance Standards
Date Submitted:
December February 123, 20162017
SAR Requester Information
Name:
Frank Koza
Organization:
PJM Interconnection / Project 2013-03 SDT Chair
Telephone:
610-666-4228
E-mail:
frank.koza@pjm.com
SAR Type (Check as many as applicable)
New Standard
Withdrawal of existing Standard
Revision to existing Standard
Urgent Action
SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The goal of this project is to address the Federal Energy Regulatory Commission (Commission) directives
contained in Order No. 830 by modifying TPL-007-1 - Transmission System Planned Performance for
Geomagnetic Disturbance Events and the benchmark GMD event used in GMD Vulnerability
Assessments or by developing an equally efficient and effective alternative.
Industry Need (What is the industry problem this request is trying to solve?):
On September 22, 2016, the Commission issued Order No. 830 approving TPL-007-1. In the order, the
Commission directed NERC to develop certain modifications to the Standard, including:
•
•
Modify the benchmark GMD event definition used for GMD Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact
assessments;
SAR Information
•
•
Require collection of GMD-related data, which and for NERC shouldto make it available to
the publicly available; and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
The Commission established a deadline of 18 months from the effective date of Order No. 830 for
completing the revisions, which is May 29, 2018.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The Standards Drafting Team (SDT) shall develop modifications to TPL-007-1 and the benchmark GMD
event that address Commission directives from Order No. 830. The work will include development of
Violation Risk Factors, Violation Severity Levels, and an Implementation Plan for the modified standards
within the deadline established by the Commission in Order No. 830.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDT shall address each of the Order No. 830 directives by developing modifications to requirements
in TPL-007-1 and related material, or the SDT shall develop an equally efficient and effective alternative.
To address concerns identified in Order No. 830, the Commission directed the following:
Benchmark GMD Event (TPL-007-1 Attachment 1 and related requirements)
• [T]he Commission, as proposed in the NOPR, directs NERC to develop revisions to the benchmark
GMD event definition so that the reference peak geoelectric field amplitude component is not
based solely on spatially-averaged data.(P.44)
• Without prejudging how NERC proposes to address the Commission’s directive, NERC’s response
to this directive should satisfy the NOPR’s concern that reliance on spatially-averaged data alone
does not address localized peaks that could potentially affect the reliable operation of the BulkPower System. (P.47)
Transformer Thermal Impact Assessment (TPL-007-1 Requirement R6)
• Consistent with our determination above regarding the reference peak geoelectric field
amplitude value, the Commission directs NERC to revise Requirement R6 to require registered
entities to apply spatially averaged and non-spatially averaged peak geoelectric field values, or
some equally efficient and effective alternative, when conducting thermal impact assessments.
(P.65)
Collection of GMD Data
• The Commission … adopts the NOPR proposal in relevant part and directs NERC to develop
revisions to Reliability Standard TPL-007-1 to require responsible entities to collect GIC
monitoring and magnetometer data as necessary to enable model validation and situational
awareness, including from any devices that must be added to meet this need. The NERC standard
Project 2013-03 Geomagnetic Disturbance Mitigation
December February 123, 20162017
2
SAR Information
•
•
drafting team should address the criteria for collecting GIC monitoring and magnetometer data...
and provide registered entities with sufficient guidance in terms of defining the data that must be
collected.... (P.88)
Each responsible entity that is a transmission owner should be required to collect necessary GIC
monitoring data. However, a transmission owner should be able to apply for an exemption from
the GIC monitoring data collection requirement if it demonstrates that little or no value would be
added to planning and operations. (P.91)
NERC may also propose to incorporate the GIC monitoring and magnetometer data collection
requirements in a different Reliability Standard....(P.91)
Deadlines for Corrective Action Plans and Mitigations (TPL-007-1 Requirement R7)
• The Commission directs NERC to modify Reliability Standard TPL-007-1 to include a deadline of
one year from the completion of the GMD Vulnerability Assessments to complete the
development of corrective action plans. (P.101)
• The Commission also directs NERC to modify Reliability Standard TPL-007-1 to include a two-year
deadline after the development of the corrective action plan to complete the implementation of
non-hardware mitigation and four-year deadline to complete hardware mitigation…. The
Commission agrees that NERC should consider extensions of time on a case-by-case basis. (P.102)
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Project 2013-03 Geomagnetic Disturbance Mitigation
December February 123, 20162017
3
Reliability Functions
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and Reactive Power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all 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.
Project 2013-03 Geomagnetic Disturbance Mitigation
December February 123, 20162017
4
Reliability and Market Interface Principles
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.
Does the proposed Standard 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.
Enter
(yes/no)
YES
YES
YES
YES
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Project 2013-03 Geomagnetic Disturbance Mitigation
December February 123, 20162017
Explanation
5
Regional Variances
Region
Explanation
FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC
Project 2013-03 Geomagnetic Disturbance Mitigation
December February 123, 20162017
6
TPL-007-2 – 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
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
December 14, 2016
SAR posted for comment
December 16, 2016
– January 20, 2017
Anticipated Actions
Date
45-day formal comment period with ballot
June 2017
45-day formal comment period with additional ballot
September 2017
10-day final ballot
TBD
Board adoption
February 2018
Draft 1 of TPL-007-2
June 2017
Page 1 of 42
TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
Draft 1 of TPL-007-2
June 2017
Page 2 of 42
TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-2
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;
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-007-1
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]
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
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
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
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
Draft 1 of TPL-007-2
June 2017
Page 5 of 42
TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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
benchmark GIC value 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.
Rationale for Requirement 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):
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
•
•
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 7.3.
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:
[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 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 revised if situations beyond the control of the responsible entity determined
in Requirement R1 prevent implementation of the CAP within the timetable for
implementation provided in Part 7.3. The 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;
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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. 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.
7.5. 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 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 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, 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.
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Supplemental GMD Vulnerability Assessment(s)
Rationale for Requirements R8 - R10: The proposed requirements address directives in
Order No. 830 for revising the benchmark GMD event used in GMD Vulnerability
Assessments (P.44, P47-49). The requirements add a supplemental GMD Vulnerability
Assessment based on the supplemental GMD event that accounts for localized peak
geoelectric fields.
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.
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. 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. 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
Draft 1 of TPL-007-2
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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: (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.
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
supplemental GIC value 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
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
GMD Measurement Data Processes
Rationale for Requirements R11 and 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). 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 6 of the 2012 Special
Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the BulkPower 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
Draft 1 of TPL-007-2
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
•
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.
R11. 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]
M11. 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 R11.
R12. 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. 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 R12.
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.
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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, 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 R11 and R12, 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-007-2 – 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
Benchmark
GMD Event -
1. System as may be
postured in response to
space weather
information1, and then
GMD Event
with Outages
Supplemental
GMD Event GMD Event
with Outages
2. GMD event2
1. System as may be
postured in response to
space weather
information1, and then
2. GMD event2
Interruption of
Firm Transmission
Service Allowed
Load Loss Allowed
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
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
Event
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-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
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.
R2.
N/A
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 study or
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the study or
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June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
N/A
N/A
N/A
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.
R4.
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
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
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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
GMD Vulnerability
Assessment;
OR
Draft 1 of TPL-007-2
June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
R5.
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.
R6.
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
transformers (whichever is
greater) where the
maximum effective GIC value
provided in Requirement R5,
Part 5.1, is 75 A or greater
per phase;
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
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC value
provided in Requirement R5,
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
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
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
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC value
provided in Requirement R5,
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R7.
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.
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
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
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
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
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
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
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June 2017
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not have a Corrective Action
Plan as required by
Requirement R7.
R8.
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;
OR
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;
Draft 1 of TPL-007-2
June 2017
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two 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
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
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.
Page 19 of 42
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
four of the 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
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R9.
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.
R10.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
Draft 1 of TPL-007-2
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R11.
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.
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
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
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
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
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
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
N/A
N/A
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.
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R12.
N/A
N/A
N/A
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
D. Regional Variances
None.
E. Associated Documents
None.
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TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
2
Draft 1 of TPL-007-2
June 2017
Date
Action
Change
Tracking
December 17, Adopted by the NERC Board of Trustees
2014
TBD
Revised to respond to directives in FERC
Order No. 830.
Revised
Page 23 of 42
TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Attachments
The following attachments are part of TPL-007-2.
Draft 1 of TPL-007-2
June 2017
Page 24 of 42
TPL-007-2 Supplemental Material
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:
Epeak = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (V/km)
Epeak = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (V/km)
(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
(3)
α = 0.001 ⋅ e ( 0.115⋅L )
where L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
The benchmark GMD event description is available on the Related Information page for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
2
The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in EastWest (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 GMD Event Description white paper on the Project 2013-03
Geomagnetic Disturbance Mitigation project page: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-GeomagneticDisturbance-Mitigation.aspx
1
Draft 1 of TPL-007-2
June 2017
Page 25 of 42
TPL-007-2 Supplemental Material
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
Scaling Factor1
(Degrees)
(α)
≤ 40
45
50
54
56
57
58
59
≥ 60
0.10
0.2
0.3
0.5
0.6
0.7
0.8
0.9
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 planning entity should use the largest β factor of adjacent physiographic regions or
a technically justified value.
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
Available at the NERC GMD Task Force project page: http://www.nerc.com/comm/PC/Pages/GeomagneticDisturbance-Task-Force-(GMDTF)-2013.aspx
4
Available at http://geomag.usgs.gov/conductivity/
3
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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)
(5)
𝛽𝛽𝑠𝑠 = 𝐸𝐸/12 for the supplemental GMD event
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.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03
Geomagnetic Disturbance Mitigation project page: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-GeomagneticDisturbance-Mitigation.aspx
5
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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
Earth model
Scaling Factor
Benchmark Event
(β b)
Scaling Factor
Supplemental Event
(β s)
AK1A
AK1B
AP1
AP2
BR1
CL1
CO1
CP1
CP2
FL1
CS1
IP1
IP2
IP3
IP4
NE1
PB1
PB2
PT1
SL1
SU1
BOU
FBK
PRU
BC
PRAIRIES
SHIELD
ATLANTIC
0.56
0.56
0.33
0.82
0.22
0.76
0.27
0.81
0.95
0.76
0.41
0.94
0.28
0.93
0.41
0.81
0.62
0.46
1.17
0.53
0.93
0.28
0.56
0.21
0.67
0.96
1.0
0.79
0.51
0.51
0.30
0.78
0.22
0.73
0.25
0.77
0.86
0.73
0.37
0.90
0.25
0.90
0.35
0.77
0.55
0.39
1.19
0.49
0.90
0.24
0.56
0.22
0.62
0.88
1.0
0.76
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.
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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
NRCan’s 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.
7
Refer to the Benchmark GMD 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 page 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)
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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
NRCan’s 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 GMD 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-GeomagneticDisturbance-Mitigation.aspx
10
The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force
project page: 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 Bn (Northward), Blue Be (Eastward)
12 V/km
12000
10000
8000
E (mV/km)
6000
4000
2000
0
200
-2000
400
600
800
1000
1200
1400
1600
1800
2000
Time (min)
-4000
-6000
-8000
Figure 7: Supplemental Geoelectric Field Waveform. Blue En (Northward), Red Ee (Eastward)
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Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
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. A white paper that
includes the event description, analysis, and example calculations is available on the Project
2013-03 Geomagnetic Disturbance Mitigation project page at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
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. A white paper that
includes the event description and analysis is available on the Project 2013-03 Geomagnetic
Disturbance Mitigation project page:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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.
The guide is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GIC%20Application%20Guide%202013_approved.pdf
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
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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 GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
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 thermal impact
assessment white paper.
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. The ERO enterprise has
endorsed the white paper as Implementation Guidance for this requirement. The white paper is
posted on the NERC compliance guidance page:
http://www.nerc.com/pa/comp/guidance/Pages/default.aspx
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
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analysis of the System. Justification for this criterion is provided in the Screening Criterion for
Transformer Thermal Impact Assessment white paper posted on the Related Information page
for TPL-007-1. 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 GMD Planning Guide. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic
Disturbances on the Bulk-Power System:
http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf
Requirement R8
The GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
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.
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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 discussed in the
Requirement R6 section above. A revised version of the Transformer Thermal Impact
Assessment white paper has been developed to include updated information pertinent to the
supplemental GMD event and supplemental thermal impact assessment. This revised white
paper is posted on the project page at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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 posted on the project page.
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 the NERC 2012 GMD Report (see
Chapter 6). 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 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.
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•
•
•
•
•
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:
•
Observatories such as those operated by U.S. Geological Survey and Natural Resources
Canada, see figure below for locations (http://www.intermagnet.org/):
• 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, which is available at:
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 GIC Application Guide
developed by the NERC GMD Task Force and available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GIC%20Application%20Guide%202013_approved.pdf
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 (RM12-1-000). NERC
guidelines require consistency among Reliability Standards.
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.
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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 GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
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
time-series 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:
[http://www.nerc.com/pa/comp/guidance/Pages/default.aspx]
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.
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
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effective GIC value of 75 A per phase or greater require evaluation in Requirement R6. The
justification is provided in the Thermal Screening Criterion white paper.
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 posted on the project
page.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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:
Corrective Action Plans are defined in the NERC Glossary of Terms:
A list of actions and an associated timetable for implementation to remedy a specific
problem.
Corrective Action Plans must, subject to the vulnerabilities identified in the assessments,
contain strategies for protecting against the potential impact of the benchmark GMD event,
based on factors such as the age, condition, technical specifications, system configuration, or
location of specific equipment. Chapter 5 of the NERC GMD Task Force GMD Planning Guide
provides a list of mitigating measures that may be appropriate to address an identified
performance issue.
The provision of information in Requirement R7, Part 7.3 [Part 7.5 in TPL-007-2], shall be
subject to the legal and regulatory obligations for the disclosure of confidential and/or sensitive
information.
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.]
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TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-12
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;
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.
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.
6.
Effective Date:
See Implementation Plan for TPL-007-12
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 and,
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessment(s)., and implementing process(es) to obtain GMD
measurement data as specified in this standard. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
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 and,
Page 1 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
performing the study or studies needed to complete benchmark and supplemental GMD
Vulnerability Assessment(s), and implementing process(es) to obtain GMD
Mmeasurement Ddata 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 Assessment(s). [Violation Risk Factor: High] [Time Horizon: Long-term
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 Assessment(s).
R3.
Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the
benchmark GMD eventevents 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.
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) within 90
calendar days of completion to the responsible entity’s Reliability Coordinator,
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TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
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, within 90 calendar
days of completion to its Reliability Coordinator, adjacent Planning Coordinator(s),
adjacent Transmission Planner(s), and to any functional entity who has submitted a
written request and has a reliability-related need 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 transformerbenchmark 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.
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
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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 benchmark GIC
value 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.
Rationale for Requirement 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
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TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
•
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 7.3.
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 offor 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 Corrective Action
PlanCAP 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 Special
Protection SystemsRemedial Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the Corrective Action PlanCAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be reviewed in subsequent GMD Vulnerability Assessments until it is determined
that the System meets the performance requirements contained in Table 1.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 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 revised if situations beyond the control of the responsible entity determined
in Requirement R1 prevent implementation of the CAP within the timetable for
implementation provided in Part 7.3. The 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;
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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. 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.
7.2.7.5.
Be provided: (i) within 90 calendar days of completiondevelopment or
revision to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the Corrective Action PlanCAP 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.
7.2.1.7.5.1. If a recipient of the Corrective Action PlanCAP 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.
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 of for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its Corrective Action PlanCAP 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 Corrective Action PlanCAP 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,within 90
calendar days of its completiondevelopment or revision to its Reliability Coordinator,
adjacent Planning Coordinator(s), adjacent Transmission Planner(s), a functional entity
referenced in the Corrective Action PlanCAP, and any functional entity that submitswho
has submitted a written request and has a reliability-related need, 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,
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TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
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that it has provided a documented response to comments received on its Corrective
Action PlanCAP within 90 calendar days of receipt of those comments, in accordance
with Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
Rationale for Requirements R8 - R10: The proposed requirements address directives
in Order No. 830 for revising the benchmark GMD event used in GMD Vulnerability
Assessments (P.44, P47-49). The requirements add a supplemental GMD Vulnerability
Assessment based on the supplemental GMD event that accounts for localized peak
geoelectric fields.
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.
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 The supplemental 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 supplemental GMD Vulnerability Assessment,
whichever is later.
8.4.1 If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
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TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
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.
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 supplemental
GIC value 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
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Events
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.
GMD Measurement Data Processes
Rationale for Requirements R11 and 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). 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 6 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.
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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
•
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.
R8.R11.
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]
M11. 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 R11.
R9.R12.
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. 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 R12.
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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
Benchmark
GMD Event -
1. System as may be
postured in response to
space weather
information1, and then
GMD Event
with Outages
Supplemental
GMD Event GMD Event
with Outages
2. GMD event2
1. System as may be
postured in response to
space weather
information1, and then
2. GMD event2
Interruption of
Firm Transmission
Service Allowed
Load Loss Allowed
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
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
Event
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 eventevents are described in Attachment 1 (Benchmark GMD Event). .
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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Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD
EventEvents
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 waveshapewaveform 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 × 𝛼𝛼 × 𝛽𝛽𝛽𝛽 𝑏𝑏 (V/km)
Epeak = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (V/km)
(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
denotes association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD event isevents are defined for geomagnetic latitude of
60° and it 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
(2)
α = 0.001 ⋅ e ( 0.115⋅L )
The benchmark GMD event description is available on the Project 2013-03 Geomagnetic Disturbance Mitigation
projectRelated Information page:http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx for TPL-007-1:: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
2
The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in EastWest (longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes.
Additional information is available in the sSupplemental GMD eEvent dDescription white paper on the Project 2013-03
Geomagnetic Disturbance Mitigation project page: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-GeomagneticDisturbance-Mitigation.aspx
1
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(3)
α = 0.001 ⋅ e ( 0.115⋅L )
where L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
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
Scaling Factor1
(Degrees)
(α)
≤ 40
45
50
54
56
57
58
59
≥ 60
0.10
0.2
0.3
0.5
0.6
0.7
0.8
0.9
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
(23) 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 AssessmentAssessments. When a ground conductivity model is not
Available at the NERC GMD Task Force project page: http://www.nerc.com/comm/PC/Pages/GeomagneticDisturbance-Task-Force-(GMDTF)-2013.aspx
3
Page 13 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
available, the planning entity should use the largest β factor of adjacent physiographic
regions or a technically justified value.
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/8𝛽𝛽 = 𝐸𝐸/8 for the benchmark GMD event
(4)
𝛽𝛽𝑠𝑠 = 𝐸𝐸/12 for the supplemental GMD event
(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:
•
•
•
4
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/
5
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03
Geomagnetic Disturbance Mitigation project page: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-GeomagneticDisturbance-Mitigation.aspx
Page 14 of 45
TPL-007-12 — 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 15 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Table 3 − Geoelectric Field Scaling Factors
USGS
Earth model
Scaling Factor
(β)Benchmark Event
(β b)
Scaling Factor
Supplemental Event
(β s)
AK1A
AK1B
AP1
AP2
BR1
CL1
CO1
CP1
CP2
FL1
CS1
IP1
IP2
IP3
IP4
NE1
PB1
PB2
PT1
SL1
SU1
BOU
FBK
PRU
BC
PRAIRIES
SHIELD
ATLANTIC
0.56
0.56
0.33
0.82
0.22
0.76
0.27
0.81
0.95
0.7476
0.41
0.94
0.28
0.93
0.41
0.81
0.62
0.46
1.17
0.53
0.93
0.28
0.56
0.21
0.67
0.96
1.0
0.79
0.51
0.51
0.30
0.78
0.22
0.73
0.25
0.77
0.86
0.73
0.37
0.90
0.25
0.90
0.35
0.77
0.55
0.39
1.19
0.49
0.90
0.24
0.56
0.22
0.62
0.88
1.0
0.76
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.
Page 16 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Table 4 − Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Page 17 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Reference Geomagnetic Field Time Series or Waveshape 7Waveform for the
Benchmark GMD Event 8
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
NRCan’s Ottawa geomagnetic observatory is the basis for the reference geomagnetic field
waveshapewaveform 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
amplitude 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
sampling rate for the geomagnetic field waveshapewaveform is 10 seconds. 9 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.βb.
7
Refer to the Benchmark GMD Event Description for details on the determination of the reference geomagnetic
field waveshape: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
8
Refer to the Benchmark GMD Event Description white paper for details on the determination of the reference
geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
9
The data file of the benchmark geomagnetic field waveshapewaveform is available on the NERC GMD Task Force
projectRelated Information page: http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force(GMDTF)-2013.aspx for TPL-007-1: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
Page 18 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Figure 3: Benchmark Geomagnetic Field WaveshapeWaveform. Red Bn (Northward), Blue Be
(Eastward)
Figure 4: Benchmark Geoelectric Field WaveshapeWaveform - EE (Eastward)
Page 19 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Figure 5: Benchmark Geoelectric Field WaveshapeWaveform – EN (Northward)
Page 20 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event10
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
NRCan’s 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
amplitude 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. 11 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 GMD 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-GeomagneticDisturbance-Mitigation.aspx
11
The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force
project page: http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx
10
Page 21 of 45
TPL-007-12 — 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
12000
10000
8000
E (mV/km)
6000
4000
2000
0
200
-2000
400
600
800
1000
1200
1400
1600
1800
2000
Time (min)
-4000
-6000
-8000
Figure 7: Supplemental Geoelectric Field Waveform. Red Blue En (Northward), Blue Red Ee
(Eastward)
Page 22 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
C. Compliance
1. Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “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 the NERCmandatory and enforceable
Reliability Standards in their respective jurisdictions.
1.2.
Evidence Retention
The following evidence retention periodsperiod(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 CEACompliance Enforcement Authority may ask
an entity to provide other evidence to show that it was compliant for the fulltime period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner, and
Generator OwnerThe 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 R6R10, each responsible
entity shall retain documentation as evidence for five years.
•
For RequirementRequirements R4 and R8, each responsible entity shall
retain documentation of the current GMD Vulnerability Assessment and
the preceding GMD Vulnerability Assessment.
•
For Requirement R7, 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 R11 and R12, each responsible entity shall retain
documentation as evidence for three years.
If a Planning Coordinator, Transmission Planner, Transmission Owner, or
Generator Owner is found non-compliant it shall keep information related to the
non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Page 23 of 45
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Events
Spot Checking
Compliance Investigations
Self-Reporting
Complaints
1.4.
Additional Compliance Information
None
Page 24 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
•
1.3.
For Requirements R11 and R12, each responsible entity shall retain
documentation as evidence for three years.
Compliance Monitoring and Assessment Processes: 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 25 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning
Lower
N/A
Moderate VSL
N/A
High VSL
N/A
Severe VSL
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
and, performing the
study or studies
needed to complete
benchmark and
supplemental GMD
Vulnerability
Assessment(s).), and
implementing
process(es) to obtain
Page 26 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
GMD measurement
data as specified in
this standard.
R2
Long-term
Planning
High
N/A
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
study or studies
needed to complete
benchmark and
supplemental GMD
Vulnerability
Assessment(s).
The responsible entity
did not maintain both
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
Assessment(s).
R3
Long-term
Planning
Medium N/A
N/A
N/A
The responsible entity
did not have criteria
for acceptable System
steady state voltage
performance for its
System during the
benchmark GMD
eventevents described
in Attachment 1 as
required.
R4
Long-term
Planning
High
The responsible
entity's completed
benchmark GMD
The responsible
entity's completed
benchmark GMD
The responsible
entity's completed
benchmark GMD
The responsible entity
completed a
benchmark GMD
Page 27 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
R5
Long-term
Planning
Medium 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
Vulnerability
Assessment failed to
satisfy one of
elements listed in
Requirement R4, Parts
4.1 through 4.3;
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 64
calendar months and
less than or equal to
68 calendar months
since the last
benchmark GMD
Vulnerability
Assessment.
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 last
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 100
calendar days and less
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
The responsible entity
did not provide the
maximum effective
GIC value to the
Transmission Owner
and Generator Owner
that owns each
OR
The responsible entity
completed a
benchmark GMD
Vulnerability
Assessment, but it
was more than 72
calendar months since
the last benchmark
GMD Vulnerability
Assessment;
OR
The responsible entity
does not have a
completed benchmark
GMD Vulnerability
Assessment.
Page 28 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
equal to 100 calendar
days after receipt of a
written request.
R6
Long-term
Planning
Medium 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
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
than or equal to 110
calendar days after
receipt of a written
request.
receipt of a written
request.
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
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 R5, Part
5.1, is 75 A or greater
per phase;
OR
The responsible entity
conducted a
benchmark thermal
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 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
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
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
Page 29 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
R7
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.
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 required
elements as listed in
Requirement R6, Parts
6.1 through 6.3.
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 required
elements as listed in
Requirement R6, Parts
6.1 through 6.3.
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 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
The responsible
entity's Corrective
Action Plan failed to
comply with two of
the elements in
The responsible
entity's Corrective
Action Plan failed to
comply with three of
the elements in
The responsible
entity's Corrective
Action Plan failed to
comply with four or
more of the elements
Page 30 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
R8
Requirement R7, Parts Requirement R7, Parts Requirement R7, Parts in Requirement R7,
7.1 through 7.5.
7.1 through 7.5.
7.1 through 7.5.
Parts 7.1 through 7.5;
OR
The responsible entity
did not have a
Corrective Action Plan
as required by
Requirement R7.
The responsible entity The responsible
The responsible
The responsible
completed a
entity's completed
entity's completed
entity's completed
supplemental GMD
supplemental GMD
supplemental GMD
supplemental GMD
Vulnerability
Vulnerability
Vulnerability
Vulnerability
Assessment, but it
Assessment failed to
Assessment failed to
Assessment failed to
was more than 60
satisfy two of
satisfy three of the
satisfy four of the
calendar months and
elements listed in
elements listed in
elements listed in
less than or equal to
Requirement R8, Parts Requirement R8, Parts Requirement R8, Parts
64 calendar months
8.1 through 8.4;
8.1 through 8.4;
8.1 through 8.4;
since the last
OR
OR
OR
supplemental GMD
The responsible entity The responsible entity The responsible entity
Vulnerability
completed a
completed a
completed a
Assessment;
supplemental
GMD
supplemental GMD
supplemental GMD
OR
Vulnerability
Vulnerability
Vulnerability
Assessment, but it
Assessment, but it
The responsible
Assessment, but it
was
more
than
68
was more than 72
entity's completed
was more than 64
calendar months and
calendar months since
supplemental GMD
calendar months and
less than or equal to
the last supplemental
Vulnerability
less than or equal to
72
calendar
months
GMD Vulnerability
Assessment failed to
68 calendar months
since the last
Assessment;
satisfy one of
since the last
supplemental GMD
elements listed in
supplemental GMD
OR
Vulnerability
Requirement R8, Parts
Assessment.
8.1 through 8.4;
Page 31 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
Vulnerability
Assessment.
R9
R10
The responsible entity
does not have a
completed
supplemental GMD
Vulnerability
Assessment.
The responsible entity The responsible entity The responsible entity The responsible entity
provided the effective provided the effective provided the effective did not provide the
GIC time series, GIC(t), GIC time series, GIC(t), GIC time series, GIC(t), maximum effective
in response to written in response to written in response to written GIC value to the
request, but did so
request, but did so
request, but did so
Transmission Owner
more than 90 calendar more than 100
more than 110
and Generator Owner
days and less than or
calendar days and less calendar days after
that owns each
equal to 100 calendar than or equal to 110
receipt of a written
applicable BES power
days after receipt of a calendar days after
request.
transformer in the
written request.
receipt of a written
planning area;
request.
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
solely owned and
jointly owned
applicable BES power
The responsible entity
failed to conduct a
supplemental 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
supplemental thermal
impact assessment for
more than 10% up to
(and including) 15% or
three of its solely
owned and jointly
The responsible entity
failed to conduct a
supplemental thermal
impact assessment for
more than 15% or
more than three of its
solely owned and
jointly owned
Page 32 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
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
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
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 33 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
R11
N/A
in Requirement R9,
Part 9.1;
OR
The responsible entity
failed to include one
of the required
elements as listed in
Requirement R10,
Parts 10.1 through
10.3.
N/A
R12
N/A
N/A
in Requirement R9,
Part 9.1;
OR
The responsible entity
failed to include two
of the required
elements as listed in
Requirement R10,
Parts 10.1 through
10.3.
N/A
N/A
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
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 34 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance Events
Page 35 of 45
TPL-007-12 — Transmission System Planned Performance for Geomagnetic Disturbance
Events
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.
Version History
Version
Date
Action
1
December 17, 2014
Adopted by the NERC Board of Trustees
2
TBD
Revised to respond to directives in FERC
Order No. 830.
Change Tracking
Revised
Page 21 of 26
Application Guidelines
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
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. A white paper that
includes the event description, analysis, and example calculations is available on the Project
2013-03 Geomagnetic Disturbance Mitigation project page at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspxhttp://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
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. A white paper that
includes the event description and analysis is available on the Project 2013-03 Geomagnetic
Disturbance Mitigation project page:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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.
The guide is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GIC%20Application%20Guide%202013_approved.pdf
Page 37 of 45
Application Guidelines
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 GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
Requirement R5
The transformerbenchmark thermal impact assessment of transformers specified in
Requirement R6 is based on GIC information for the Benchmarkbenchmark 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.
Page 38 of 45
Application Guidelines
The maximum effective GIC value provided in Part 5.1 is used for transformerthe 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 transformerthe 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 thermal impact
assessment white paper.
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 posted on the project
page.. The ERO enterprise has endorsed the white paper as Implementation Guidance for this
requirement. The white paper is posted on the NERC compliance guidance page:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
http://www.nerc.com/pa/comp/guidance/Pages/default.aspx
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 posted on the Related Information page
for projectTPL-007-1. 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 GMD Planning Guide. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic
Disturbances on the Bulk-Power System:
http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf
Requirement R8
Page 39 of 45
Application Guidelines
The GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
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 discussed in the
Requirement R6 section above. A revised version of the Transformer Thermal Impact
Assessment white paper has been developed to include updated information pertinent to the
supplemental GMD event and supplemental thermal impact assessment. This revised white
paper is posted on the project page at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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
Page 40 of 45
Application Guidelines
Criterion for Transformer Thermal Impact Assessment white paper posted on the project page.
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 the NERC 2012 GMD Report (see
Chapter 6). 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 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 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.
Page 41 of 45
Application Guidelines
•
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 (http://www.intermagnet.org/):
•
•
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, which is available at:
http://www.intermagnet.org/publications/intermag_4-6.pdf
Page 42 of 45
Application Guidelines
Rationale:
During development of this standardTPL-007-1, text boxes were embedded within the standard
to explain the rationale for various parts of the standard. Upon BOT approval, theThe 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 GIC Application Guide
developed by the NERC GMD Task Force and available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GIC%20Application%20Guide%202013_approved.pdf
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 (RM12-1-000). NERC
guidelines require consistency among Reliability Standards.
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.
Page 43 of 45
Application Guidelines
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 GMD Planning Guide developed by the NERC GMD Task Force provides technical
information on GMD-specific considerations for planning studies. It is available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%
202013/GMD%20Planning%20Guide_approved.pdf
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
time-series 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:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
[http://www.nerc.com/pa/comp/guidance/Pages/default.aspx]
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.
Rationale for R6:
Page 44 of 45
Application Guidelines
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 Thermal Screening Criterion white paper.
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 posted on the project
page.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
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:
Corrective Action Plans are defined in the NERC Glossary of Terms:
A list of actions and an associated timetable for implementation to remedy a specific
problem.
Corrective Action Plans must, subject to the vulnerabilities identified in the assessments,
contain strategies for protecting against the potential impact of the Benchmark[Bb]enchmark
GMD event, based on factors such as the age, condition, technical specifications, system
configuration, or location of specific equipment. Chapter 5 of the NERC GMD Task Force GMD
Planning Guide provides a list of mitigating measures that may be appropriate to address an
identified performance issue.
The provision of information in Requirement R7, Part 7.3, [Part 7.5 in TPL-007-2], shall be
subject to the legal and regulatory obligations for the disclosure of confidential and/or sensitive
information.
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 (FL-1) has been updated to 0.76 in TPL-0072 based on the earth model published on the USGS public website.]
Page 45 of 45
Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Reliability Standard TPL-007-2
Applicable Standard(s)
•
TPL-007-2 - Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement(s)
•
TPL-007-1 - Transmission System Planned Performance for Geomagnetic Disturbance Events
Prerequisite Standard(s)
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;
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 September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL-007-1 and its associated five-year Implementation Plan. In the
Order, FERC also directed NERC to develop certain modifications to the standard. FERC established a
deadline of 18 months from the effective date of Order No. 830 for completing the revisions, which
is May 2018.
General Considerations
This Implementation Plan is intended to integrate the new requirements in TPL-007-2 with the GMD
Vulnerability Assessment process that is being implemented through approved TPL-007-1. At the
time of the May 2018 filing deadline, many requirements in approved standard TPL-007-1 that lead
to completion of the GMD Vulnerability Assessment will be in effect. Furthermore, many entities
may be taking steps to complete studies or assessments that are required by future enforceable
requirements in TPL-007-1. The Implementation Plan phases in the requirements in TPL-007-2 based
on the effective date of TPL-007-2, as follows:
•
Effective Date before January 1, 2021. Implementation timeline supports applicable entities
completing new requirements for supplemental GMD Vulnerability Assessments
concurrently with requirements for the benchmark GMD Vulnerability Assessment
(concurrent effective dates).
•
Effective Date on or after January 1, 2021. Implementation timeline supports applicable
entities completing the benchmark GMD Vulnerability Assessments before new
requirements for supplemental GMD Vulnerability Assessments become effective.
Effective Date and Phased-In Compliance Dates
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 a proposed Reliability Standard (e.g., an entire Requirement or a portion
thereof), the additional time for compliance with that section is specified below. The phased-in
compliance date for those particular sections represents the date 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.
Standard TPL-007-2
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 three (3) 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 three (3) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
If TPL-007-2 becom es effective before January 1, 2021
Implementation timeline supports applicable entities completing new requirements for
supplemental GMD Vulnerability Assessments concurrently with requirements for the benchmark
GMD Vulnerability Assessment (concurrent effective dates).
Compliance Date for TPL-007-2 Requirement R9
Entities shall not be required to comply with Requirement R9 until six (6) months after the effective
date of Reliability Standard TPL-007-2.
Implementation Plan
Project 2013-03 GMD Mitigation | June 2017
2
Compliance Date for TPL-007-2 Requirements R11 and R12
Entities shall not be required to comply with Requirements R11 and R12 until 24 months after the
effective date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until 30 months after the
effective date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until 42 months after the
effective date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirement R7
Entities shall not be required to comply with Requirement R7 until 54 months after the effective
date of Reliability Standard TPL-007-2.
If TPL-007-2 becom es effective on or after January 1, 2021
Implementation timeline supports applicable entities completing the benchmark GMD Vulnerability
Assessments before new requirements for supplemental GMD Vulnerability Assessments become
effective.
Compliance Date for TPL-007-2 Requirements R3 and R4
Entities shall not be required to comply with Requirements R3 and R4 until 12 months after the
effective date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirements R7, R11, and R12
Entities shall not be required to comply with Requirements R7, R11, and R12 until 24 months after
the effective date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirement R9
Entities shall not be required to comply with Requirement R9 until 36 months after the effective
date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirement R10
Entities shall not be required to comply with Requirement R10 until 60 months after the effective
date of Reliability Standard TPL-007-2.
Compliance Date for TPL-007-2 Requirement R8
Entities shall not be required to comply with Requirement R8 until 72 months after the effective
date of Reliability Standard TPL-007-2.
Implementation Plan
Project 2013-03 GMD Mitigation | June 2017
3
Retirement Date
Standard TPL-007-1
Reliability Standard TPL-007-1 shall be retired immediately prior to the effective date of TPL-007-2 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 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 2013-03 GMD Mitigation | June 2017
4
Supplemental
Geomagnetic
Disturbance Event
Description
Project 2013-03 GMD Mitigation
June 2017
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
General Characteristics .......................................................................................................................................... iv
Supplemental GMD Event Description .......................................................................................................................1
Supplemental GMD Event Geoelectric Field Amplitude .........................................................................................1
Supplemental Geomagnetic Field Waveform .........................................................................................................1
Appendix I – Technical Considerations.......................................................................................................................3
Statistical Considerations........................................................................................................................................3
Extreme Value Analysis .......................................................................................................................................4
Spatial Considerations ............................................................................................................................................7
Local Enhancement Waveform............................................................................................................................ 13
Transformer Thermal Assessment ....................................................................................................................... 15
Appendix II – Scaling the Supplemental GMD Event ............................................................................................... 16
Scaling the Geomagnetic Field ............................................................................................................................. 16
Scaling the Geoelectric Field ................................................................................................................................ 18
References ............................................................................................................................................................... 22
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
ii
Preface
The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority
whose mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC
develops and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the
BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of
responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico.
NERC is the Electric Reliability Organization (ERO) for North America, subject to oversight by the Federal Energy
Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users,
owners, and operators of the BPS, which serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and
corresponding table below.
The North American BPS is divided into eight RE boundaries. The highlighted areas denote 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
SPP RE
Southwest Power Pool Regional Entity
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
iii
Introduction
Background
Proposed TPL-007-2 includes requirements for entities to perform two types of GMD Vulnerability Assessments
to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
•
•
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated with
TPL-007-1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order No. 830 in
September 2016. The benchmark GMD event is derived from spatially-averaged geoelectric field values
to address potential wide-area effects that could be caused by a severe 1-in-100 year GMD event. 1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event described in
this white paper, is used by entities to evaluate localized enhancements of geomagnetic field during a
severe GMD event that "could potentially affect the reliable operation of the Bulk-Power System". 2
Localized enhancements of geomagnetic field can result in geoelectric field values above the spatiallyaveraged benchmark in a local area.
The purpose of the supplemental geomagnetic disturbance (GMD) event description is to provide a defined event
for assessing system performance for a GMD event which includes a local enhancement of the geomagnetic field.
In addition to varying with time, geomagnetic fields can be spatially non-uniform with higher and lower strengths
across a region. This spatial non-uniformity has been observed in a number of GMD events, so localized
enhancement of field strength above the average value is considered. The supplemental GMD event defines the
geomagnetic and geoelectric field values used to compute geomagnetically-induced current (GIC) flows for a
supplemental GMD Vulnerability Assessment.
General Characteristics
The supplemental GMD event described herein takes into consideration observed characteristics of a local
geomagnetic field enhancement, recognizing that the science and understanding of these events is evolving.
Based on observations and initial assessments, the characteristics of local enhancements include:
•
•
•
•
Geographic area – The extent of local enhancements is on the order of 100km in North-South (latitude)
direction but longer in East-West (longitude) direction. Further description of the geographic area is
provided later in the white paper.
Amplitude – The amplitude of the resulting geoelectric field is significantly higher than the geoelectric
field that is calculated in the spatially-averaged Benchmark GMD event.
Duration – The local enhancement in the geomagnetic field occurs over a time period of 2-5 minutes.
Geoelectric field waveform – The supplemental GMD event waveform is the benchmark GMD event
waveform with the addition of a local enhancement. The added local enhancement has amplitude and
duration characteristics described above. The geoelectric field waveform has a strong influence on the
hot spot heating of transformer windings and structural parts since thermal time constants of the
transformer and time to peak of storm maxima are both on the order of minutes. The frequency content
of the rate of change of the magnetic field (dB/dt) is a function of the waveform, which in turn has a direct
effect on the geoelectric field since the earth response to dB/dt is frequency-dependent. As with the
benchmark GMD event, the supplemental GMD event waveform is based on magnetic field data recorded
by the Natural Resources Canada (NRCan) Ottawa (OTT) geomagnetic observatory during the March 13-
See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in
RM 15-11 on June 28, 2016.
2
See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the
benchmark GMD event, included in TPL-007-1, such that assessments would not be based solely on spatially
averaged data.
1
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Introduction
14 1989 event. This GMD event data was selected because analysis of recorded events indicates that the
OTT observatory data for this period provides conservative results when performing thermal assessments
of power transformers. 3
3
See Benchmark Geomagnetic Disturbance Event Description white paper, page 5 and Appendix I.
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Supplemental GMD Event Description
Severe geomagnetic disturbance events are high-impact, low-frequency (HILF) events [1]; thus, GMD events used
in system planning should consider the probability that the event will occur, as well as the impact or consequences
of such an event. The supplemental GMD event is composed of the following elements: 1) a reference peak
geoelectric field amplitude (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.
Supplemental GMD Event Geoelectric Field Amplitude
The supplemental GMD event field amplitude was determined through statistical analysis using the plane wave
method [2]-[9] of geomagnetic field measurements from geomagnetic observatories in northern Europe [10] and
the reference (Quebec) earth model shown in Table 1 [11], supplemented by data from Greenland, Denmark and
Alaska. For details of the statistical considerations, see Appendix I. The Quebec earth model is generally resistive
and the geological structure is relatively well understood.
Table 1: Reference Earth Model (Quebec)
Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
The statistical analysis (see Appendix I) resulted in conservative peak geoelectric field amplitude of approximately
12 V/km. For steady-state GIC and load flow analysis, the direction of the geoelectric field is assumed to be variable
meaning that it can be in any direction (Eastward, Northward, or a vectorial combination thereof).
The regional geoelectric field peak amplitude, Epeak, to be used in calculating GIC in the GIC system model can be
obtained from the reference value of 12 V/km using the following relationship
Epeak = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (V/km)
(1)
where α is the scaling factor to account for local geomagnetic latitude, and βS is a scaling factor for the
supplemental GMD event to account for the local earth conductivity structure (see Appendix II).
Supplemental Geomagnetic Field Waveform
The supplemental geomagnetic field waveform is the benchmark geomagnetic field waveform with the addition
of a local enhancement. Both the benchmark and supplemental geomagnetic field waveforms are used to
calculate the GIC time series, GIC(t), required for transformer thermal impact assessments. The supplemental
waveform includes a local enhancement, inserted at UT 1:18 March 14 in Figure 1 below. This time corresponds
to the largest calculated geoelectric fields during the benchmark GMD event. The amplitude of the local
enhancement is based on a statistical analysis of a number of GMD events, discussed in Appendix I. The duration
of the enhancement is based on the characteristics of observed localized enhancements as discussed in Appendix
I.
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Supplemental GMD Event Description
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the amplitude of the
geomagnetic field measurement data with a local enhancement was scaled up to the 60° reference geomagnetic
latitude (see Figure 1) such that the resulting peak geoelectric field amplitude computed using the reference earth
model was 12 V/km (see Figure 2). Sampling rate for the geomagnetic field waveform is 10 seconds.
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 1: Supplemental Geomagnetic Field Waveform
Red Bx (Northward), Blue By (Eastward),
Referenced to pre-event quiet conditions
15000
Ex, Ey (mV/km)
10000
5000
0
200
400
600
800
1000
1200
1400
1600
Time (min)
-5000
-10000
Figure 2: Supplemental Geoelectric Field Waveform
Red Ey (Eastward), Blue Ex (Northward)
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Appendix I – Technical Considerations
The following sections describe the technical justification of the assumptions that were made in the development
of the supplemental GMD event.
Statistical Considerations
The peak geoelectric field amplitude of the supplemental GMD event was determined through statistical analysis
of modern 10-second geomagnetic field data and corresponding calculated geoelectric field amplitudes. The
objective of the analysis was to estimate the geoelectric field amplitude that is associated with a 1 in 100 year
frequency of occurrence. The same data set and similar statistical techniques were used in determining the peak
geoelectric field amplitude of the benchmark GMD event, including extreme value analysis discussed in the
following section. 4 The fundamental difference in the supplemental GMD event amplitude is that it is based on
observations taken at each individual station (i.e., localized measurements), in contrast with the spatially averaged
geoelectric fields used in the Benchmark Geomagnetic Disturbance Event Description white paper. 5
See Benchmark Geomagnetic Disturbance Event Description white paper, Appendix I, pages 8-13.
Averaging the geoelectric field values of stations in geographic groups is referred to as spatial averaging
in the Benchmark Geomagnetic Disturbance Event Description. Spatial averaging was used to characterize GMD
events over a geographic area relevant to the interconnected transmission system for purposes of assessing area
effects such as voltage collapse and widespread equipment risk. See Benchmark Geomagnetic Disturbance Event
Description white paper, Appendix I, pages 9-10.
4
5
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Appendix I – Technical Considerations
Extreme Value Analysis
The objective of extreme value analysis is to describe the behavior of a stochastic process at extreme deviations
from the median. In general, the intent is to quantify the probability of an event more extreme than any previously
observed. In particular, we are concerned with estimating the 95% confidence interval of the maximum
geoelectric field amplitude to be expected within a 100-year return period. 6
The data set consists of 23 years of daily maximum geoelectric field amplitudes derived from individual stations
in the IMAGE magnetometer chain, using the Quebec earth model as a reference. Figure I-1 shows a scatter plot
of geoelectric field amplitudes that exceed 2 V/km across the IMAGE stations. The plot indicates that there is
seasonality in extreme observations associated with the 11-year solar cycle.
Figure I-1: Scatter Plot of Geoelectric Fields that Exceed a 2 V/km Threshold
Data source: IMAGE magnetometer chain from 1993-2015.
6
A 95 percent confidence interval means that, if repeated samples were obtained, the return level would
lie within the confidence interval for 95 percent of the samples.
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Appendix I – Technical Considerations
Several statistical methods can be used to conduct extreme value analysis. The most commonly applied include:
Generalized Extreme Value (GEV), Point Over Threshold (POT), R-Largest, and Point Process (PP). In general, all
methods assume independent and identically distributed (iid) data [12].
Table I-1 shows a summary of the estimated parameters and return levels obtained from different statistical
methods. The parameters were estimated using the Maximum Likelihood Estimator (MLE). Since the distribution
parameters do not have an intuitive interpretation, the expected geoelectric field amplitude for a 100-year return
period is also included in Table I-1. The 95% confidence interval of the 100-year return level was calculated using
the delta method and the profile likelihood. The delta method relies on the Gaussian approximation to the
distribution of the MLE; this approximation can be poor for long return periods. In general, the profile likelihood
provides a better description of the return level.
Table I-1: Extreme Value Analysis
Estimated
Parameters
Statistical Model
(1) GEV
(2) GEV,
reparametrization
t
µ = β 0 + β1 ⋅ sin + φ
T
(3) POT, threshold=2
V/km
3 day decluster.
143 observations >
2V/km.
(4) POT,
threshold=2V/km
reparametrization,
t
σ = β 0 + β1 ⋅ sin + φ
T
µ=2.976
(0.193)
σ=0.829
(0.1357)
ξ=-0.0655
(0.1446)
β0= 2.964
(0.151)
β1=0.582
(0.155)
σ=0.627
(0.114)
ξ=0.09
(0.183)
σ=0.592
(0.074)
ξ=0.077
(0.093)
β0=0.58
(0.073)
β1=0.107
(0.082)
ξ=0.037
(0.097)
100 Year Return Level
95% CI
95% CI
Delta
P-Likelihood
[V/km]
[V/km]
Hypothesis
Testing
Mean
[V/km]
H0: ξ=0
p = 0.66
6.9
[4.3, 8.2]
[5.2, 11.4]
7.1
[4, 10.2]
[5.5, 18]
6.9
[4.5, 9.4]
[5.4, 11.9]
7
[4.6, 9.3]
[5.5, 11.7]
H0: β1=0
p = 0.00
H0: ξ=0
p = 0.6
H0: B1=0
p = 0.2
Statistical model (1) in Table I-1 is the traditional GEV estimation using blocks of 1 year maxima; i.e., only 23 data
points are used in the estimation. The mean expected amplitude of the geoelectric field for a 100-year return level
is approximately 7 V/km. Since GEV works with blocks of maxima, it is typically regarded as a wasteful approach.
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Appendix I – Technical Considerations
As discussed previously, GEV assumes that the data is iid. Based on the scatter plot shown in Figure I-1, the iid
statistical assumption is not warranted by the data. Statistical model (2) in Table I-1 is a reparametrization of the
GEV distribution contemplating the 11-year seasonality in the mean,
t
+φ
T
µ = β 0 + β1 ⋅ sin
where β0 represents the offset in the mean, β1 describes the 11-year seasonality, T is the period (11 years), and φ
is a constant phase shift.
A likelihood ratio test is used to test the hypothesis that β1 is zero. The null hypothesis, H0: β1=0, is rejected with
a p-value of 0.0032; as expected, the 11-year seasonality has explanatory power. The blocks of maxima during the
solar minimum are better represented in the reparametrized GEV. The mean return level is still 7 V/km, but the
confidence interval is wider, [5.5, 18] V/km for the profile likelihood (calculated at solar maximum).
Statistical model (3) in Table I-1 is the traditional POT estimation using a threshold u of 2 V/km; the data was
declustered using a 1-day run. The data set consists of normalized excesses over a threshold, and therefore, the
sample size for POT is increased if more than one extreme observation per year is available (in the GEV approach,
only the maximum observation over the year was taken; in the POT method, a single year can have multiple
observations over the threshold). The selection of the threshold u is a compromise between bias and variance.
The asymptotic basis of the model relies on a high threshold; too low a threshold will likely lead to bias. On the
other hand, too high a threshold will reduce the sample size and result in high variance. A threshold of 2V/km was
determined to be a good choice, giving rise to 143 observations above the threshold.
The mean return level for statistical model (3), ~7 V/km, is consistent with the GEV estimates. However, due to
the larger sample size the POT method is more efficient rendering a confidence interval of [5.4, 11.9] V/km for the
profile likelihood method.
In an attempt to cope with potential heteroskedasticity in the data, a reparametrization of POT is proposed in
statistical model (4) in Table I-1,
t
+φ
T
σ = α 0 + α1 ⋅ sin
where α0 represents the offset in the standard deviation, α1 describes the 11-year seasonality, T is the period
(365.25 ∙ 11), and φ is a constant phase shift.
The parameter α1 is not statistically significant; the null hypothesis, H0: α1=0, is not rejected with a p-value of 0.2.
The proposed reparametrization does not have explanatory power, and consequently, the mean return level 7
V/km and confidence intervals remain virtually unchanged [5.5, 11.7]. As a final remark, it is emphasized that the
confidence interval obtained using the profile likelihood is preferred over the delta method.
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Appendix I – Technical Considerations
Figure I-2 shows the profile likelihood of the 100-year return level of statistical model (3). Note that the profile
likelihood is highly asymmetric with a positive skew, rendering a larger upper limit for the confidence interval.
Recall that the delta method assumes a normal distribution for the MLEs, and therefore, the confidence interval
is symmetric around the mean.
-79
-80
Profile Likelihood
-81
-82
-83
-84
-85
5
6
7
8
9
10
11
12
100 Year Return Period [V/km]
Figure I-2: Profile Likelihood for 100-year Return Level for Statistical Model (3)
To conclude, the traditional GEV (1) is misspecified; the statistical assumptions (iid) are not warranted by the data.
The model was reparametrized to cope with seasonality in the data. Statistical models (3) and (4) better utilize
the available extreme measurements and they are therefore preferred over statistical model (2). A geoelectric
field amplitude of 12 V/km is selected for the supplemental GMD event to represent the upper limit of the 95
percent confidence interval for a 100-year return interval.
Spatial Considerations
The spatial structure of high-latitude geomagnetic fields can be very complex during strong geomagnetic storm
events [13]-[14]. One reflection of this spatial complexity is localized geomagnetic field enhancements (local
enhancements) that result in high amplitude geoelectric fields in regions of a few hundred kilometers. Figure I-3
illustrates this spatial complexity of the storm-time geoelectric fields. 7 In areas indicated by the bright red location,
the geoelectric field can be substantially larger than at neighboring locations. These enhancements are primarily
the result of external (geomagnetic field) conditions, and not local geological factors such as coastal effects. 8
Figure I-3 is for illustration purposes only, and is not meant to suggest that a particular area is more
likely to experience a localized enhanced geoelectric field. The depiction is not to scale.
8
Localized externally-driven geomagnetic phenomena should not be confused with localized geoelectric
field enhancements due to complex electromagnetic response of the ground to external excitation. Complex 3D
geological conditions such as those at coastal regions can lead to localized geoelectric field enhancements but
those are not considered here.
7
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Appendix I – Technical Considerations
Figure I-3: Illustration of the Spatial Scale between Localized Enhancements and Larger
Spatial Scale Amplitudes of Geoelectric Field during a Strong Geomagnetic Storm.
In this figure, the red rectangle illustrates a spatially localized field enhancement.
The supplemental GMD event is designed to address local effects caused by a severe GMD event, such as increased
var absorption and voltage depressions.
A number of GMD events were analyzed to identify the basic characteristics of local enhancements. Three (3)
solar storms studied and described below are:
•
•
•
March 13, 1989
October 29-30, 2003
March 17, 2015
Four localized events within those storms were identified and analyzed. Geomagnetic field recordings were
collected for these storms and the geoelectric field was computed using the 1D plane wave method and the
reference Quebec ground model. In each case, a local enhancement was correlated, generally oriented parallel
to the westward ionospheric electrojet associated with ongoing larger scale geomagnetic activity. (See Figures
I-4 ̶ I-7 below)
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Appendix I – Technical Considerations
BFE Station
Spatially correlated enhancement
Figure I-4: March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark
NAQ Station
Spatiallycorrelated
correlatedenhancement
enhancement
Spatially
Figure I-5: October 29, 2003, at 06:47 UT, Narsarsuaq (NAQ), Greenland
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Appendix I – Technical Considerations
HOP Station
Figure I-6: October 30, 2003, at 16:49UT, Hopen Island (HOP), Svalbard, Norway
DED Station
Spatially correlated enhancement
Figure I-7: March 17, 2015, at 13:33 UT, Deadhorse, Alaska
All of the above events were analyzed by reviewing the time series magnetic field data and transforming it to an
electric field and focusing on the time period of the spatially correlated local enhancement. There were apparent
similarities in the character of the local enhancements. The local enhancements occurred during peak periods of
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Appendix I – Technical Considerations
geomagnetic activity and were distinguished by relatively brief excursions of rapid magnetic field variation. With
respect to time duration, the local enhancements generally occurred over a period of 2-5 minutes. (See Figures
I-8 ̶ I-11)
Figure I-8: Geoelectric field March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark.
Figure I-9: Geoelectric field October 29, 2003, at 06:47 UT, Narsarsuaq (NAQ), Greenland
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Appendix I – Technical Considerations
Figure I-10: Geoelectric field October 30, 2003, at 16:49UT, Hopen Island (HOP), Norway
Figure I-11 – Geoelectric field March 17, 2015, at 13:33 UT, Deadhorse, Alaska
Based on the above analysis and the previous work associated with the benchmark GMD event, it is reasonable
to incorporate a second (or supplemental) assessment into TPL-007 to account for the potential impact of a local
enhancement in both the network analysis and the transformer thermal assessment(s).
With respect to geographic area of the localized enhancement, the historical geomagnetic field data analyzed so
far provides some insight. Analysis suggests that the enhancements will occur in a relatively narrow band of
geomagnetic latitude (on the order of 100 km) and wider longitudinal width (on the order of 500 km) as a
consequence of the westward-oriented structure of the source in the ionosphere.
Proposed TPL-007-2 provides flexibility for planners to determine how to apply the supplemental GMD event to
the planning area. Acceptable approaches include but are not limited to:
•
Apply the peak geoelectric field for the supplemental GMD event (12 V/km scaled to the planning area)
over the entire planning area;
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Appendix I – Technical Considerations
•
•
Apply a spatially limited (e.g., 100 km in North-South direction and 500 km in East-West direction)
geoelectric field enhancement (12 V/km scaled to the planning area) over a portion(s) of the system, and
apply the benchmark GMD event over the rest of the system.
Other methods to adjust the benchmark GMD event analysis for localized geoelectric field enhancement.
Given the current state of knowledge regarding the spatial extent of a local geomagnetic field enhancements,
upper geographic boundaries, such as the values used in the approaches above, are reasonable but are not
definitive.
Local Enhancement Waveform
The supplemental geomagnetic field waveform was derived by modifying the benchmark GMD event waveform
to emulate the observed events described above. The temporal location of the enhancement corresponds to the
time of the benchmark event with the highest geoelectric field. The local enhancement was constructed by scaling
linearly a 5-minute portion of the benchmark geomagnetic field so that the peak geoelectric field is 12 V/km at a
geomagnetic latitude of 60° and reference earth model. Figure I-12 shows the benchmark geomagnetic field and
Figure I-13 shows the supplemental event geomagnetic field. Figure I-14 expands the view into Bx, with and
without the local enhancement. Figure I-15 is the corresponding expanded view of the geoelectric field magnitude
with and without the local enhancement.
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
Time of highest geoelectric field
Figure I-12: Benchmark Geomagnetic Field. Red Bx (Northward), Blue By (Eastward)
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Appendix I – Technical Considerations
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
Local enhancement
-10000
Figure I-13: Supplemental Geomagnetic Field Waveform. Red Bx (Northward), Blue By
(Eastward)
-1000
5 minutes
-2000
Bx (nT)
-3000
-4000
-5000
-6000
Benchmark
-7000
-8000
Enhancement
-9000
1480
1490
1500
1510
1520
1530
1540
1550
Time (min)
Figure I-14: Red Benchmark Bx and Blue Supplemental Bx (Northward) – Expanded View
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Appendix I – Technical Considerations
12000
Enhancement (12 V/km)
|E| (mV/km)
10000
8000
Benchmark (8V/km)
6000
4000
2000
0
1500
1510
1520
1530
1540
1550
Time (min)
Figure I-15: Magnitude of the Geoelectric Field. Benchmark Blue and Supplemental Red –
Expanded View
Transformer Thermal Assessment
The local enhancement of the supplemental GMD event waveform can have a material impact on the temperature
rise (hot-spot heating or metallic parts) even though the duration of the local enhancement is approximately 5
minutes. Thermal assessments based on the supplemental GMD event can be performed using the same methods
employed for benchmark thermal assessments. 9
9
See Transformer Thermal Impact Assessment white paper: http://www.nerc.com/pa/Stand/Pages/Project-2013-03Geomagnetic-Disturbance-Mitigation.aspx
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Appendix II – Scaling the Supplemental GMD Event
The intensity of a GMD event depends on geographical considerations such as geomagnetic latitude and local
earth conductivity [2]. 10 Scaling factors for geomagnetic latitude take into consideration that the intensity of a
GMD event varies according to latitude-based geographical location. Scaling factors for earth conductivity take
into account that the induced geoelectric field depends on earth conductivity, and that different parts of the
continent have different earth conductivity and deep earth structure.
Scaling the supplemental GMD event differs from the benchmark GMD event in two ways:
•
•
Epeak is 12 V/km instead of 8 V/km
Beta factors for scaling the geoelectric field based on earth conductivity are different (see Table II-2)
More discussion, including example calculations, is contained in the Benchmark GMD Event Description white
paper.
Scaling the Geomagnetic Field
The supplemental GMD event is defined for geomagnetic latitude of 60° and it must be scaled to account for
regional differences based on geomagnetic latitude. To allow usage of the supplemental geomagnetic field
waveform in other locations, Table II-1 summarizes the scaling factor α correlating peak geoelectric field to
geomagnetic latitude as described in Figure II-1 [3]. This scaling factor α has been obtained from a large number
of global geomagnetic field observations of all major geomagnetic storms since the late 1980s [15]-[27], and can
be approximated with the empirical expression in (II.1)
α = 0.001 ⋅ e ( 0.115⋅L )
(II.1)
where L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.0.
10
Geomagnetic latitude is analogous to geographic latitude, except that bearing is in relation to the magnetic poles, as opposed to
the geographic poles. Geomagnetic phenomena are often best organized as a function of geomagnetic coordinates. Local earth conductivity
refers to the electrical characteristics to depths of hundreds of km down to the earth’s mantle. In general terms, lower ground conductivity
results in higher geoelectric field amplitudes.
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Appendix II – Scaling the Supplemental GMD Event
Figure II-1: Geomagnetic Latitude Lines in North America
Table II-1: Geomagnetic Field Scaling Factors
Geomagnetic Latitude
Scaling Factor1
(Degrees)
(α)
≤ 40
45
50
54
56
57
58
59
≥ 60
0.10
0.2
0.3
0.5
0.6
0.7
0.8
0.9
1.0
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Appendix II – Scaling the Supplemental GMD Event
Scaling the Geoelectric Field
The supplemental GMD event is defined for the reference Quebec earth model provided in Table 1. This earth
model has been used in many peer-reviewed technical articles [11, 15]. The peak geoelectric field depends on the
geomagnetic field waveform and the local earth conductivity. Ideally, the peak geoelectric field, Epeak, is obtained
by calculating the geoelectric field from the scaled geomagnetic field waveform using the plane wave method and
taking the maximum value of the resulting waveforms
E N = ( z (t ) / µ o ) * BE (t )
E E = −( z (t ) / µ o ) * BN (t )
E peak = max{E E (t ), E N (t ) }
(II.2)
where,
* denotes convolution in the time domain,
z(t) is the impulse response for the earth surface impedance calculated from the laterally uniform or 1D earth
model,
BE(t), BN(t) are the scaled Eastward and Northward geomagnetic field waveforms,
EE(t), EN(t)| are the magnitudes of the calculated Eastward and Northward geoelectric field EE(t) and EN(t).
As noted previously, the response of the earth to B(t) (and dB/dt) is frequency dependent. Figure II-2 shows the
magnitude of Z(ω) for the reference earth model.
Figure II-2: Magnitude of the Earth Surface Impedance for the Reference Earth Model
If a utility does not have the capability of calculating the waveform or time series for the geoelectric field, an earth
conductivity scaling factor βS can be obtained from Table II-2. Using α and β, the peak geoelectric field Epeak for a
specific service territory shown in Figure II-3 can be obtained using (II.3)
Epeak 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (V/km)
It should be noted that (II.3) is an approximation based on the following assumptions:
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(II.3)
Appendix II – Scaling the Supplemental GMD Event
•
•
•
•
The earth models used to calculate Table II-2 for the United States are from published information
available on the USGS website. These scaling factors are slightly lower than the ones in the benchmark
because the supplemental benchmark waveform has a higher frequency content at the time of the local
enhancement.
The models used to calculate Table II-2 for Canada were obtained from NRCan and reflect the average
structure for large regions. When models are developed for sub-regions, there will be variance (to a
greater or lesser degree) from the average model. For instance, detailed models for Ontario have been
developed by NRCan and consist of seven major sub-regions.
The conductivity scaling factor βS is calculated as the quotient of the local geoelectric field peak amplitude
in a physiographic region with respect to the reference peak amplitude value of 12 V/km. Both geoelectric
field peak amplitudes are calculated using the supplemental geomagnetic field time series. If a different
geomagnetic field time series were used, the calculated scaling factors (β) would be different than the
values in Table II-2 because the frequency content of storm maxima is, in principle, different for every
storm. If a utility has technically-sound earth models for its service territory and sub-regions thereof, then
the use of such earth models is preferable to estimate Epeak.
When a ground conductivity model is not available the planning entity should use the largest βs factor of
adjacent physiographic regions or a technically-justified value.
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
19
Appendix II – Scaling the Supplemental GMD Event
Physiographic Regions of the Continental United States
FL-1
Physiographic Regions of Canada
Figure II-3: Physiographic Regions of North America
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
20
Appendix II – Scaling the Supplemental GMD Event
Table II-2 Supplemental Geoelectric Field Scaling Factors
Earth model
Scaling Factor (β)
AK1A
AK1B
AP1
AP2
BR1
CL1
CO1
CP1
CP2
FL1
CS1
IP1
IP2
IP3
IP4
NE1
PB1
PB2
PT1
SL1
SU1
BOU
FBK
PRU
BC
PRAIRIES
SHIELD
ATLANTIC
0.51
0.51
0.30
0.78
0.22
0.73
0.25
0.77
0.86
0.73
0.37
0.90
0.25
0.90
0.35
0.77
0.55
0.39
1.19
0.49
0.90
0.24
0.56
0.22
0.62
0.88
1.0
0.76
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
21
References
[1]
High-Impact, Low-Frequency Event Risk to the North American Bulk Power System, A JointlyCommissioned Summary Report of the North American Reliability Corporation and the U.S.
Department of Energy’s November 2009 Workshop.
[2]
Application Guide: Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC.
NERC.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%20201
3/GIC%20Application%20Guide%202013_approved.pdf
[3]
Kuan Zheng, Risto Pirjola, David Boteler, Lian-guang Liu, “Geoelectric Fields Due to Small-Scale and
Large-Scale Source Currents”, IEEE Transactions on Power Delivery, Vol. 28, No. 1, January 2013, pp.
442-449.
[4]
Boteler, D. H. “Geomagnetically Induced Currents: Present Knowledge and Future Research”, IEEE
Transactions on Power Delivery, Vol. 9, No. 1, January 1994, pp. 50-58.
[5]
Boteler, D. H. “Modeling Geomagnetically Induced Currents Produced by Realistic and Uniform Electric
Fields”, IEEE Transactions on Power Delivery, Vol. 13, No. 4, January 1998, pp. 1303-1308.
[6]
J. L. Gilbert, W. A. Radasky, E. B. Savage, “A Technique for Calculating the Currents Induced by
Geomagnetic Storms on Large High Voltage Power Grids”, Electromagnetic Compatibility (EMC), 2012
IEEE International Symposium on.
[7]
How to Calculate Electric Fields to Determine Geomagnetically-Induced Currents. EPRI, Palo Alto, CA:
2013. 3002002149.
[8]
Pulkkinen, A., R. Pirjola, and A. Viljanen, Statistics of extreme geomagnetically induced current events,
Space Weather, 6, S07001, doi:10.1029/2008SW000388, 2008.
[9]
Boteler, D. H., Assessment of geomagnetic hazard to power systems in Canada, Nat. Hazards, 23, 101–
120, 2001.
[10] Finnish Meteorological Institute’s IMAGE magnetometer chain data available at:
http://image.gsfc.nasa.gov/
[11] Boteler, D. H., and R. J. Pirjola, The complex-image method for calculating the magnetic and electric
fields produced at the surface of the Earth by the auroral electrojet, Geophys. J. Int., 132(1), 31—40,
1998
[12] Coles, Stuart (2001). An Introduction to Statistical Modelling of Extreme Values. Springer.
[13] Pulkkinen, A., A. Thomson, E. Clarke, and A. Mckay, April 2000 geomagnetic storm: ionospheric drivers
of large geomagnetically induced currents, Annales Geophysicae, 21, 709-717, 2003.
[14] Pulkkinen, A., S. Lindahl, A. Viljanen, and R. Pirjola, Geomagnetic storm of 29–31 October 2003:
Geomagnetically induced currents and their relation to problems in the Swedish high-voltage power
transmission system, Space Weather, 3, S08C03, doi:10.1029/2004SW000123, 2005.
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
22
References
[15] Pulkkinen, A., E. Bernabeu, J. Eichner, C. Beggan and A. Thomson, Generation of 100-year
geomagnetically induced current scenarios, Space Weather, Vol. 10, S04003,
doi:10.1029/2011SW000750, 2012.
[16] Ngwira, C., A. Pulkkinen, F. Wilder, and G. Crowley, Extended study of extreme geoelectric field event
scenarios for geomagnetically induced current applications, Space Weather, Vol. 11, 121–131,
doi:10.1002/swe.20021, 2013.
[17] Thomson, A., S. Reay, and E. Dawson. Quantifying extreme behavior in geomagnetic activity, Space
Weather, 9, S10001, doi:10.1029/2011SW000696, 2011.
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
23
Screening Criterion for Transformer Thermal
Impact Assessment
Project 2013-03 (Geomagnetic Disturbance Mitigation)
TPL-007-2 Transmission System Planned Performance for Geomagnetic Disturbance
Events
Summary
Proposed TPL-007-2 includes requirements for entities to perform two types of GMD Vulnerability
Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
•
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL-007-1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially-averaged
geoelectric field values to address potential wide-area effects that could be caused by a severe 1-in100 year GMD event.1
•
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate risks that localized peaks in geomagnetic field during a severe GMD event
"could potentially affect the reliable operation of the Bulk-Power System". 2 Localized
enhancements of geomagnetic field can result in geoelectric field values above the spatiallyaveraged benchmark in a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye-grounded windings with terminal voltage greater than 200 kV. Identified
BES transformers must undergo a thermal impact assessment if the maximum effective geomagneticallyinduced current (GIC) in the transformer is equal to or greater than:
•
•
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
Based on published power transformer measurement data as described below, the respective screening
criteria are conservative and, although derived from measurements in single-phase units, are applicable to
transformers with all core types (e.g., three-limb, three-phase).
1
2016.
See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15-11 on June 28,
See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event,
included in TPL-007-1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for
this assessment are in the Supplemental GMD Event Description white paper.
2
Outside of the differing screening criteria, the only difference between the thermal impact assessment for
the benchmark GMD event and the supplemental GMD event is that a different waveform is used, therefore
peak metallic hot spot temperatures are slightly different for a given GIC in the transformer.
Justification for the Benchmark Screening Criterion
Applicable entities are required to carry out a thermal assessment with GIC(t) calculated using the
benchmark GMD event geomagnetic field time series or waveform for effective GIC values above a
screening threshold. The calculated GIC(t) for every transformer will be different because the length and
orientation of transmission circuits connected to each transformer will be different even if the geoelectric
field is assumed to be uniform. However, for a given thermal model and maximum effective GIC there are
upper and lower bounds for the peak hot spot temperatures. These are shown in Figure 1 using three
available thermal models based on direct temperature measurements.
The results shown in Figure 1 summarize the peak metallic hot spot temperatures when GIC(t) is calculated
using (1), and systematically varying GICE and GICN to account for all possible orientation of circuits
connected to a transformer. The transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be
calculated using equation (1) from reference [1].
GIC (t ) = E (t ) ⋅ {GIC E sin(ϕ (t )) + GIC N cos(ϕ (t ))}
(1)
E (t ) = E N2 (t ) + E E2 (t )
(2)
where
E E (t )
E N (t )
ϕ (t ) = tan −1
GIC (t ) = EE (t ) ⋅ GICE + EN (t ) ⋅ GICN
(3)
(4)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km.
It should be emphasized that with the thermal models used and the benchmark GMD event geomagnetic
field waveform, peak metallic hot spot temperatures will lie below the envelope shown in black in Figure 1.
The x-axis in Figure 1 corresponds to the absolute value of peak GIC(t). Effective maximum GIC for a
transformer corresponds to a worst-case geoelectric field orientation, which is network-specific. Figure 1
represents a possible range, not the specific thermal response for a given effective GIC and orientation.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
2
Figure 1: Metallic hot spot temperatures calculated using the benchmark GMD event.
Red: SVC coupling transformer model [2]. Blue: Fingrid model [3]. Green: Autotransformer model [4].
Consequently, with the most conservative thermal models known at this point in time, the peak metallic
hot spot temperature obtained with the benchmark GMD event waveform assuming an effective GIC
magnitude of 75 A per phase will result in a peak temperature between 160°C and 172°C when the bulk oil
temperature is 80°C (full load bulk oil temperature). The upper boundary of 172°C remains well below the
metallic hot spot 200°C threshold for short-time emergency loading suggested in IEEE Std C57.91-2011 ̶
Guide for Loading Mineral-Oil-Immersed Transformers and Step-Voltage Regulators [5].
The selection of the 75 A per phase screening threshold is based on the following considerations:
•
•
A thermal assessment, which uses the most conservative thermal models known to date, indicates
that a GIC of 75A will not result in peak metallic hot spot temperatures above 172°C. Transformer
thermal assessments should not be required by Reliability Standards when results will fall well below
IEEE Std C57.91-2011 limits.
Applicable entities may choose to carry out a thermal assessment when the effective GIC is below
75 A per phase to take into account the age or condition of specific transformers where IEEE Std
C57.91- 2011 limits could be assumed to be lower than 200°C. Refer to IEEE Standard C57.163-2015
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
3
•
•
•
•
•
Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances for
additional information [6].
The models used to determine the 75 A per phase screening threshold are known to be conservative
at higher values of effective GIC, especially the SVC coupling transformer model in [2].
Thermal models in peer-reviewed technical literature, especially those calculated models without
experimental validation, are less conservative than the models used to determine the screening
threshold. Therefore, a technically-justified thermal assessment for effective GIC below 75 A per
phase using the benchmark GMD event geomagnetic field waveform will always result in a “pass”
on the basis of the state of the knowledge at this point in time.
Based on simulations, the 75 A per phase screening threshold will result in a maximum
instantaneous peak hot spot temperature of 172°C. However, IEEE Std C57.91- 2011 limits assume
short term emergency operation (typically 30 minutes). As illustrated in Figure 2, simulations of the
75 A per phase screening threshold result in 30-minute duration hot spot temperatures of about
155°C. The threshold provides an added measure of conservatism in not taking into account the
duration of hot spot temperatures.
The models used in the determination of the threshold are conservative but technically justified.
Winding hot spots are not the limiting factor in terms of hot spots due to half-cycle saturation,
therefore the screening criterion is focused on metallic part hot spots only.
The 75 A per phase screening threshold was determined using single-phase transformers, but is being
applied as a screening criterion for all types of transformer construction. While it is known that some
transformer types such as three-limb, three-phase transformers are intrinsically less susceptible to GIC, it
is not known by how much, on the basis of experimentally-supported models.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
4
Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event.
Red: metallic hot spot temperature. Blue: GIC(t) that produces the maximum hot spot temperature with
peak GIC(t) scaled to 75 A/phase.
Justification for the Supplemental Screening Criterion
As in the case for the benchmark GMD event discussed above, applicable entities are required to carry out
thermal assessments on their BES power transformers when the effective GIC values are above a screening
threshold. GIC(t) for supplemental thermal assessments is calculated using the supplemental GMD event
geomagnetic field time series or waveform.
Using the supplemental GMD event waveform, a thermal analysis was completed for the two
transformers that were limiting for the benchmark waveform. The results are shown in Figure 3. Peak
metallic hot spot temperatures for the supplemental GMD event will lie below the envelope shown by the
black line trace in Figure 3. Because the supplemental waveform has a sharper peak, the peak metallic hot
spot temperatures are slightly lower than those associated with the benchmark waveform. Applying the
most conservative thermal models known at this point in time, the peak metallic hot spot temperature
obtained with the supplemental GMD event waveform assuming an effective GIC magnitude of 85 A per
phase will result in a peak temperature of 172°C when the bulk oil temperature is 80°C (full load bulk oil
temperature). 3 Thus, 85 A per phase is the screening level for the supplemental waveform.
3
The temperature 172°C was selected as the screening criteria for the benchmark waveform as described in the preceding section.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
5
Figure 3: Metallic hot spot temperatures calculated using the supplemental GMD event.
Green: SVC coupling transformer model [2]. Red: Autotransformer model [4]
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
6
Appendix I - Transformer Thermal Models Used in the Development of
the Screening Criteria
The envelope used for thermal screening (Figure 1) is derived from two thermal models. The first is based
on laboratory measurements carried out on 500/16.5 kV 400 MVA single-phase Static Var Compensator
(SVC) coupling transformer [2]. Temperature measurements were carried out at relatively small values of
GIC (see Figure I-1). The asymptotic thermal response for this model is the linear extrapolation of the
known measurement values. Although the near-linear behavior of the asymptotic thermal response is
consistent with the measurements made on a Fingrid 400 kV 400 MVA five-leg core-type fully-wound
transformer [3] (see Figures I-2 and I-3), the extrapolation from low values of GIC is very conservative, but
reasonable for screening purposes.
The second transformer model is based on a combination of measurements and modeling for a 400 kV
400 MVA single-phase core-type autotransformer [4] (see Figures I-4 and I-5). The asymptotic thermal
behavior of this transformer shows a “down-turn” at high values of GIC as the tie plate increasingly
saturates but relatively high temperatures for lower values of GIC. The hot spot temperatures are higher
than for the two other models for GIC less than 125 A per phase.
18
Temperature (deg. C)
16
14
12
10
8
6
4
2
0
0
5
10
15
20
25
30
Time (min)
Figure I-1: Thermal step response of the tie plate of a 500 kV 400 MVA single-phase SVC
coupling transformer to a 5 A per phase dc step.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
7
35
Temperature (deg. C)
30
25
20
15
10
5
0
0
5
10
15
20
25
30
35
40
45
Time (min)
Figure I-2: Step thermal response of the top yoke clamp of a 400 kV 400 MVA five-leg coretype fully-wound transformer to a 16.67 A per phase dc step.
200
Temperature (deg. C)
180
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-3: Asymptotic thermal response of the top yoke clamp of a 400 kV 400 MVA five-leg
core-type fully-wound transformer.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
8
70
Temperature (deg. C)
60
50
40
30
20
10
0
0
10
20
30
Time (min)
Figure I-4: Step thermal response of the tie plate of a 400 kV 400 MVA single-phase coretype autotransformer to a 10 A per phase dc step.
180
Temperature (deg. C)
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-5: Asymptotic thermal response of the tie plate of a 400 kV 400 MVA single-phase
core-type autotransformer.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
9
The envelope in Figure 1 can be used as a conservative thermal assessment for effective GIC values of
associated with the benchmark waveform (see Table 1).
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
90
Metallic hot spot
Temperature (°C )
80
107
128
139
148
157
169
170
172
175
179
Effective GIC
(A/phase)
100
110
120
130
140
150
160
170
180
190
200
Metallic hot spot
Temperature (°C )
182
186
190
193
204
213
221
230
234
241
247
For instance, if effective GIC is 130 A per phase and oil temperature is assumed to be 80°C, peak hot spot
temperature is 193°C. This value is below the 200°C IEEE Std C57.91-2011 threshold for short time
emergency loading and this transformer will have passed the thermal assessment. If the full heat run oil
temperature is 67°C at maximum ambient temperature, then 150 A per phase of effective GIC translates
into a peak hot spot temperature of 200°C and the transformer will have passed. If the limit is lowered to
180°C to account for the condition of the transformer, then this would be an indication to “sharpen the
pencil” and perform a detailed assessment. Some methods are described in Reference [1].
The temperature envelope in Figure 1 corresponds to the values of effective GIC that result in the highest
temperature for the benchmark GMD event. Different values of effective GIC could result in lower
temperatures using the same model. For instance, the difference in upper and lower bounds of peak
temperatures for the SVC coupling transformer model for 150 A per phase is approximately 30°C. In this
case, GIC(t) should be generated to calculate the peak temperatures for the actual configuration of the
transformer within the system as described in Reference [1]. Alternatively, a more precise thermal
assessment could be carried out with a thermal model that more closely represents the thermal behavior
of the transformer under consideration.
Similar to the discussion above, the envelope in Figure 3 can be used as a conservative thermal
assessment for effective GIC values of associated with the supplemental waveform (see Table 2). Because
the supplemental waveform has a sharper peak, the peak metallic hot spot temperatures associated with
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
10
the supplemental waveform are slightly lower than those associated with the benchmark waveform.
Comparing Tables 1 and 2 shows the magnitude of this difference.
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
85
90
100
110
Metallic hot spot
Temperature (°C )
80
107
124
137
147
156
161
162
165
169
172
177
181
185
Effective
GIC(A/phase)
120
130
140
150
160
170
180
190
200
220
230
250
275
300
Metallic hot spot
Temperature (°C )
188
191
194
198
203
209
214
229
237
248
253
276
298
316
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
11
References
[1] Transformer Thermal Impact Assessment white paper. Developed by the Project 2013-03
(Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[2] Marti, L., Rezaei-Zare, A., Narang, A., "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents," IEEE Transactions on Power Delivery, vol.28, no.1, pp.320-327,
Jan. 2013.
[3] Lahtinen, Matti. Jarmo Elovaara. “GIC occurrences and GIC test for 400 kV system transformer”. IEEE
Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
[4] J. Raith, S. Ausserhofer: “GIC Strength verification of Power Transformers in a High Voltage
Laboratory”, GIC Workshop, Cape Town, April 2014
[5] "IEEE Guide for Loading Mineral-Oil-Immersed Transformers and Step-Voltage Regulators." IEEE Std
C57.91-2011 (Revision of IEEE Std C57.91-1995).
[6] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.”
IEEE Std C57.163-2015.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | June 2017
12
Screening Criterion for Transformer Thermal
Impact Assessment
Project 2013-03 (Geomagnetic Disturbance Mitigation)
TPL-007-12 Transmission System Planned Performance for Geomagnetic
Disturbance Events
Summary
Proposed standard TPL-007-1 – Transmission System Planned Performance for Geomagnetic Disturbance
Events requires applicable entities to conduct assessments of the potential impact of benchmark GMD
events on their systems. The standard requires transformer thermal impact assessments to be performed
on power transformers with high side, wye-grounded windings with terminal voltage greater than 200 kV.
Transformers are exempt from the thermal impact assessment requirement if the maximum effective
geomagnetically-induced current (GIC) in the transformer is less than75 A per phase as determined by GIC
analysis of the system. Based on published power transformer measurement data as described below, an
effective GIC of 75 A per phase is a conservative screening criterion. To provide an added measure of
conservatism, the 75 A per phase threshold, although derived from measurements in single-phase units, is
applicable to transformers with all core types (e.g., three-limb, three-phase).
Proposed TPL-007-2 includes requirements for entities to perform two types of GMD Vulnerability
Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
•
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL-007-1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially-averaged
geoelectric field values to address potential wide-area effects that could be caused by a severe 1-in100 year GMD event.1
•
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate risks that localized peaks in geomagnetic field during a severe GMD event
"could potentially affect the reliable operation of the Bulk-Power System". 2 Localized
enhancements of geomagnetic field can result in geoelectric field values above the spatiallyaveraged benchmark in a local area.
1
2016.
See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15-11 on June 28,
See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event,
included in TPL-007-1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for
this assessment are in the Supplemental GMD Event Description white paper.
2
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye-grounded windings with terminal voltage greater than 200 kV. Identified
BES transformers must undergo a thermal impact assessment if the maximum effective geomagneticallyinduced current (GIC) in the transformer is equal to or greater than:
•
•
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
Based on published power transformer measurement data as described below, the respective screening
criteria are conservative and, although derived from measurements in single-phase units, are applicable to
transformers with all core types (e.g., three-limb, three-phase).
Outside of the differing screening criteria, the only difference between the thermal impact assessment for
the benchmark GMD event and the supplemental GMD event is that a different waveform is used, therefore
peak metallic hot spot temperatures are slightly different for a given GIC in the transformer.
Justification for the Benchmark Screening Criterion
Applicable entities are required to carry out a thermal assessment with GIC(t) calculated using the
benchmark GMD event geomagnetic field time series or waveshapewaveform for effective GIC values
above a screening threshold. The calculated GIC(t) for every transformer will be different because the length
and orientation of transmission circuits connected to each transformer will be different even if the
geoelectric field is assumed to be uniform. However, for a given thermal model and maximum effective GIC
there are upper and lower bounds for the peak hot spot temperatures. These are shown in Figure 1 using
three available thermal models based on direct temperature measurements.
The results shown in Figure 1 summarize the peak metallic hot spot temperatures when GIC(t) is calculated
using (1), and systematically varying GICE and GICN to account for all possible orientation of circuits
connected to a transformer. The transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be
calculated using equation (1) from reference [1].
GIC (t ) = E (t ) ⋅ {GIC E sin(ϕ (t )) + GIC N cos(ϕ (t ))}
(1)
E (t ) = E N2 (t ) + E E2 (t )
(2)
where
E E (t )
E N (t )
ϕ (t ) = tan −1
(3)
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | May 2016June
2017
2
GIC (t ) = EE (t ) ⋅ GICE + E N (t ) ⋅ GICN
(4)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase/ per V/km.
It should be emphasized that with the thermal models used and the benchmark GMD event geomagnetic
field waveshapewaveform, peak metallic hot spot temperatures mustwill lie below the envelope shown in
black in Figure 1. The x-axis in Figure 1 corresponds to the absolute value of peak GIC(t). Effective maximum
GIC for a transformer corresponds to a worst-case geoelectric field orientation, which is network-specific.
Figure 1 represents a possible range, not the specific thermal response for a given effective GIC and
orientation.
Figure 1: Metallic hot spot temperatures calculated using the benchmark GMD event. Red:
SVC coupling transformer model [2]. Blue: Fingrid model [3]. Green: Autotransformer model [4].
Red: SVC coupling transformer model [2]. Blue: Fingrid model [3]. Green: Autotransformer model [4].
Consequently, with the most conservative thermal models known at this point in time, the peak metallic
hot spot temperature obtained with the benchmark GMD event waveshapewaveform assuming an
effective GIC magnitude of 75 A per phase will result in a peak temperature between 160°C and 172°C when
the bulk oil temperature is 80°C (full load bulk oil temperature). The upper boundary of 172°C remains well
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | May 2016June
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3
below the metallic hot spot 200°C threshold for short-time emergency loading suggested in IEEE Std C57.912011 [5] (see Table 1). ̶ Guide for Loading Mineral-Oil-Immersed Transformers and Step-Voltage Regulators
[5].
TABLE 1:
Excerpt from Maximum Temperature Limits Suggested in IEEE C57.91-2011
Planned
loading
Normal life beyond
Long-time Short-time
expectancy nameplate emergency emergency
loading
rating
loading
loading
Insulated conductor hottest-spot
temperature °C
Other metallic hot-spot temperature
(in contact and not in contact with
insulation), °C
Top-oil temperature °C
120
130
140
180
140
150
160
200
105
110
110
110
The selection of the 75 A per phase screening threshold is based on the following considerations:
•
•
•
•
•
A thermal assessment using, which uses the most conservative thermal models known to date,
indicates that a GIC of 75A will not result in peak metallic hot spot temperatures above 172°C.
Transformer thermal assessments should not be required by Reliability Standards when results will
fall well below IEEE Std C57.91-2011 limits.
Applicable entities may choose to carry out a thermal assessment when the effective GIC is below
75 A per phase to take into account the age or condition of specific transformers where IEEE Std
C57.91- 2011 limits could be assumed to be lower than 200°C. Refer to IEEE Standard C57.163-2015
Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances for
additional information [6].
The models used to determine the 75 A per phase screening threshold are known to be conservative
at higher values of effective GIC, especially the SVC coupling transformer model in [2].
Thermal models in peer-reviewed technical literature, especially those calculated models without
experimental validation, are less conservative than the models used to determine the screening
threshold. Therefore, a technically-justified thermal assessment for effective GIC below 75 A per
phase using the benchmark GMD event geomagnetic field waveshapewaveform will always result
in a “pass” on the basis of the state of the knowledge at this point in time.
Based on simulations, the 75 A per phase screening threshold will result in a maximum
instantaneous peak hot spot temperature of 172°C. However, IEEE Std C57.91- 2011 limits assume
short term emergency operation (typically 30 minutes). As illustrated in Figure 2, simulations of the
75 A per phase screening threshold result in 30-minute duration hot spot temperatures of about
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | May 2016June
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•
•
155°C. The threshold provides an added measure of conservatism in not taking into account the
duration of hot spot temperatures.
The models used in the determination of the threshold are conservative but technically justified.
Winding hot spots are not the limiting factor in terms of hot spots due to half-cycle saturation,
therefore the screening criterion is focused on metallic part hot spots only.
The 75 A per phase screening threshold was determined using single-phase transformers, but is applicable
tobeing applied as a screening criterion for all types of transformer construction. While it is known that
some transformer types such as three-limb, three-phase transformers are intrinsically less susceptible to
GIC, it is not known by how much, on the basis of experimentally-supported models.
Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event. Red:
metallic hot spot temperature. Blue: GIC(t) that produces the maximum hot spot temperature with peak
GIC(t) scaled to 75 A/phase.
Red: metallic hot spot temperature. Blue: GIC(t) that produces the maximum hot spot temperature with
peak GIC(t) scaled to 75 A/phase.
Justification for the Supplemental Screening Criterion
As in the case for the benchmark GMD event discussed above, applicable entities are required to carry out
thermal assessments on their BES power transformers when the effective GIC values are above a screening
threshold. GIC(t) for supplemental thermal assessments is calculated using the supplemental GMD event
geomagnetic field time series or waveform.
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Using the supplemental GMD event waveform, a thermal analysis was completed for the two
transformers that were limiting for the benchmark waveform. The results are shown in Figure 3. Peak
metallic hot spot temperatures for the supplemental GMD event will lie below the envelope shown by the
black line trace in Figure 3. Because the supplemental waveform has a sharper peak, the peak metallic hot
spot temperatures are slightly lower than those associated with the benchmark waveform. Applying the
most conservative thermal models known at this point in time, the peak metallic hot spot temperature
obtained with the supplemental GMD event waveform assuming an effective GIC magnitude of 85 A per
phase will result in a peak temperature of 172°C when the bulk oil temperature is 80°C (full load bulk oil
temperature). 3 Thus, 85 A per phase is the screening level for the supplemental waveform.
Figure 3: Metallic hot spot temperatures calculated using the supplemental GMD event.
Green: SVC coupling transformer model [2]. Red: Autotransformer model [4]
3
The temperature 172°C was selected as the screening criteria for the benchmark waveform as described in the preceding section.
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Appendix I - Transformer Thermal Models Used in the Development of
the Screening Criteria
The envelope used for thermal screening (Figure 1) is derived from two thermal models. The first is based
on laboratory measurements carried out on 500/16.5 kV 400 MVA single-phase Static Var Compensator
(SVC) coupling transformer [2]. Temperature measurements were carried out at relatively small values of
GIC (see Figure 3I-1). The asymptotic thermal response for this model is the linear extrapolation of the
known measurement values. Although the near-linear behavior of the asymptotic thermal response is
consistent with the measurements made on a Fingrid 400 kV 400 MVA five-leg core-type fully-wound
transformer [3] (see Figures 4I-2 and 5I-3), the extrapolation from low values of GIC is very conservative,
but reasonable for screening purposes.
The second transformer model is based on a combination of measurements and modeling for a 400 kV
400 MVA single-phase core-type autotransformer [4] (see Figures 6I-4 and 7I-5). The asymptotic thermal
behavior of this transformer shows a “down-turn” at high values of GIC as the tie plate increasingly
saturates but relatively high temperatures for lower values of GIC. The hot spot temperatures are higher
than for the two other models for GIC less than 125 A per phase.
18
Temperature (deg. C)
16
14
12
10
8
6
4
2
0
0
5
10
15
20
25
30
Time (min)
Figure 3: I-1: Thermal step response of the tie plate of a 500 kV 400 MVA single-phase SVC
coupling transformer to a 5 A per phase dc step.
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35
Temperature (deg. C)
30
25
20
15
10
5
0
0
5
10
15
20
25
30
35
40
45
Time (min)
Figure 4I-2: Step thermal response of the top yoke clamp of a 400 kV 400 MVA five-leg coretype fully-wound transformer to a 16.67 A per phase dc step.
200
Temperature (deg. C)
180
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure 5: I-3: Asymptotic thermal response of the top yoke clamp of a 400 kV 400 MVA fiveleg core-type fully-wound transformer.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | May 2016June
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60
Temperature (deg. C)
50
40
30
20
10
0
0
5
10
15
20
25
30
Time (min)
70
Temperature (deg. C)
60
50
40
30
20
10
0
0
10
20
30
Time (min)
Figure 6I-4: Step thermal response of the tie plate of a 400 kV 400 MVA single-phase coretype autotransformer to a 10 A per phase dc step.
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180
Temperature (deg. C)
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure 7I-5: Asymptotic thermal response of the tie plate of a 400 kV 400 MVA single-phase
core-type autotransformer.
The envelope in Figure 1 can be used as a conservative thermal assessment for effective GIC values of 75
A per phase and greaterassociated with the benchmark waveform (see Table 21).
Table 21: Upper Bound of Peak Metallic Hot Spot Temperatures
Calculated Using the Benchmark GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
90
Metallic hot spot
Temperature (°C )
80
107
128
139
148
157
169
170
172
175
179
Effective GIC
(A/phase)
100
110
120
130
140
150
160
170
180
190
200
Metallic hot spot
Temperature (°C )
182
186
190
193
204
213
221
230
234
241
247
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For instance, if effective GIC is 130 A per phase and oil temperature is assumed to be 80°C, peak hot spot
temperature is 193°C. This value is below the 200°C IEEE Std C57.91-2011 threshold for short time
emergency loading and this transformer will have passed the thermal assessment. If the full heat run oil
temperature is 67°C at maximum ambient temperature, then 150 A per phase of effective GIC translates
into a peak hot spot temperature of 200°C and the transformer will have passed. If the limit is lowered to
180°C to account for the condition of the transformer, then this would be an indication to “sharpen the
pencil” and perform a detailed assessment. Some methods are described in Reference [1].
The temperature envelope in Figure 1 corresponds to the values of effective GIC that result in the highest
temperature for the benchmark GMD event. Different values of effective GIC could result in lower
temperatures using the same model. For instance, the difference in upper and lower bounds of peak
temperatures for the SVC coupling transformer model for 150 A per phase is approximately 30°C. In this
case, GIC(t) should be generated to calculate the peak temperatures for the actual configuration of the
transformer within the system as described in Reference [1]. Alternatively, a more precise thermal
assessment could be carried out with a thermal model that more closely represents the thermal behavior
of the transformer under consideration.
Similar to the discussion above, the envelope in Figure 3 can be used as a conservative thermal
assessment for effective GIC values of associated with the supplemental waveform (see Table 2). Because
the supplemental waveform has a sharper peak, the peak metallic hot spot temperatures associated with
the supplemental waveform are slightly lower than those associated with the benchmark waveform.
Comparing Tables 1 and 2 shows the magnitude of this difference.
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
85
90
Metallic hot spot
Temperature (°C )
80
107
124
137
147
156
161
162
165
169
172
177
Effective
GIC(A/phase)
120
130
140
150
160
170
180
190
200
220
230
250
Metallic hot spot
Temperature (°C )
188
191
194
198
203
209
214
229
237
248
253
276
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100
110
181
185
275
300
298
316
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References
[1] Transformer Thermal Impact Assessment white paper. Developed by the Project 2013-03
(Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspxhttp://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[2] Marti, L., Rezaei-Zare, A., Narang, A., "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents," IEEE Transactions on Power Delivery, vol.28, no.1, pp.320-327,
Jan. 2013.
[3] Lahtinen, Matti. Jarmo Elovaara. “GIC occurrences and GIC test for 400 kV system transformer”. IEEE
Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
[4] J. Raith, S. Ausserhofer: “GIC Strength verification of Power Transformers in a High Voltage
Laboratory”, GIC Workshop, Cape Town, April 2014
[5] [5] "IEEE Guide for loading mineral-oil-immersed transformersLoading Mineral-Oil-Immersed
Transformers and step-voltage regulatorsStep-Voltage Regulators." IEEE Std C57.91-2011 (Revision of
IEEE Std C57.91-1995).
[6] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.”
IEEE Std C57.163-2015.
Screening Criterion for Transformer Thermal Impact Assessment: Project 2013-03 (Geomagnetic Disturbance Mitigation) | May 2016June
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13
Transformer Thermal Impact Assessment
White Paper
TPL-007-2 ̶ Transmission System Planned Performance for Geomagnetic
Disturbance Events
Background
Proposed TPL-007-2 includes requirements for entities to perform two types of GMD Vulnerability
Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
•
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL-007-1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially-averaged
geoelectric field values to address potential wide-area effects that could be caused by a severe 1-in100 year GMD event.1
•
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate localized peaks in geomagnetic field during a severe GMD event that "could
potentially affect the reliable operation of the Bulk-Power System."2 Localized enhancements of
geomagnetic field can result in geoelectric field values above the spatially-averaged benchmark in
a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye-grounded windings with terminal voltage greater than 200 kV. Large
power transformers connected to the EHV transmission system can experience both winding and structural
hot spot heating as a result of GMD events. TPL-007-2 requires owners of such BES transformers to conduct
thermal analyses to determine if the BES transformers will be able to withstand the thermal transient
effects associated with the GMD events. BES Transformers must undergo a thermal impact assessment if
the maximum effective geomagnetically-induced current (GIC) in the transformer is equal to or greater
than: 3
•
•
1
2016.
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15-11 on June 28,
See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event,
included in TPL-007-1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for
this assessment are in the Supplemental GMD Event Description white paper.
3
See Screening Criterion for Transformer Thermal Impact Assessment for technical justification.
2
This white paper discusses methods that can be employed to conduct transformer thermal impact
assessments, including example calculations. The first version of the white paper was developed by the
Project 2013-03 GMD Standards Drafting Team (SDT) for TPL-007-1 and was endorsed by the Electric
Reliability Organization (ERO) as implementation guidance in October 2016. The SDT has updated the white
paper to include the supplemental GMD event that is added in TPL-007-2 to address directives in FERC
Order No. 830.
The primary impact of GMDs on large power transformers is a result of the quasi-dc current that flows
through wye-grounded transformer windings. This geomagnetically-induced current (GIC) results in an
offset of the ac sinusoidal flux resulting in asymmetric or half-cycle saturation (see Figure 1).
Half-cycle saturation results in a number of known effects:
• Hot spot heating of transformer windings due to harmonics and stray flux;
• Hot spot heating of non-current carrying transformer metallic members due to stray flux;
• Harmonics;
• Increase in reactive power absorption; and
• Increase in vibration and noise level.
λ
λ
λdc
Lair-core
λm
Lu
θ
o
π/2
im
o
o
im
π
GIC
Vm
− π/2
θ = ωt
θ
ibias
Figure 1: Mapping Magnetization Current to Flux through Core Excitation Characteristics
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
2
This paper focuses on hot spot heating of transformer windings and non current-carrying metallic parts.
Effects such as the generation of harmonics, increase in reactive power absorption, vibration, and noise
are not within the scope of this document.
Technical Considerations
The effects of half-cycle saturation on HV and EHV transformers, namely localized “hot spot” heating, are
relatively well understood, but are difficult to quantify. A transformer GMD impact assessment must
consider GIC amplitude, duration, and transformer physical characteristics such as design and condition
(e.g., age, gas content, and moisture in the oil). A single threshold value of GIC cannot be justified as a “pass
or fail” screening criterion where “fail” means that the transformer will suffer damage. A single threshold
value of GIC only makes sense in the context where “fail” means that a more detailed study is required.
Such a threshold would have to be technically justifiable and sufficiently low to be considered a conservative
value of GIC.
The following considerations should be taken into account when assessing the thermal susceptibility of a
transformer to half-cycle saturation:
•
In the absence of manufacturer specific information, use the temperature limits for safe transformer
operation such as those suggested in the IEEE Std C57.91-2011 (IEEE Guide for Loading Mineral-oilimmersed Transformers and Step-voltage Regulators) for hot spot heating during short-term
emergency operation [1]. This standard does not suggest that exceeding these limits will result in
transformer failure, but rather that it will result in additional aging of cellulose in the paper-oil
insulation and the potential for the generation of gas bubbles in the bulk oil. Thus, from the point
of view of evaluating possible transformer damage due to increased hot spot heating, these
thresholds can be considered conservative for a transformer in good operational condition.
•
The worst case temperature rise for winding and metallic part (e.g., tie plate) heating should be
estimated taking into consideration the construction characteristics of the transformer as they
pertain to dc flux offset in the core (e.g., single-phase, shell, 5 and 3-leg three-phase construction).
•
Bulk oil temperature due to ambient temperature and transformer loading must be added to the
incremental temperature rise caused by hot spot heating. For planning purposes, maximum ambient
and loading temperature should be used unless there is a technically justified reason to do
otherwise.
•
The time series or “waveform” of the reference GMD event in terms of peak amplitude, duration,
and frequency of the geoelectric field has an important effect on hot spot heating. Winding and
metallic part hot spot heating have different thermal time constants, and their temperature rise will
be different if the GIC currents are sustained for 2, 10, or 30 minutes for a given GIC peak amplitude.
•
The “effective” GIC in autotransformers (reflecting the different GIC ampere-turns in the common
and the series windings) must be used in the assessment. The effective current Idc,eq in an
autotransformer is defined by [2].
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
3
I dc , eq = I H + ( I N / 3 − I H )VX / VH
(1)
where
IH is the dc current in the high voltage winding;
IN is the neutral dc current;
VH is the rms rated voltage at HV terminals;
VX is the rms rated voltage at the LV terminals.
Transformer Thermal Impact Assessment Process
A simplified thermal assessment may be based on the appropriate tables from the “Screening Criterion for
Transformer Thermal Impact Assessment” white paper [3]. 4 Each table below provides the peak metallic
hot spot temperatures that can be reached for the given GMD event using conservative thermal models.
To use each table, one must select the bulk oil temperature and the threshold for metallic hot spot
heating, for instance, from reference [1] after allowing for possible de-rating due to transformer
condition. If the effective GIC results in higher than threshold temperatures, then the use of a detailed
thermal assessment as described below should be carried out.5
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
Temperature (°C )
(A/phase)
Temperature (°C )
0
80
100
182
10
107
110
186
20
128
120
190
30
139
130
193
40
148
140
204
50
157
150
213
60
169
160
221
70
170
170
230
75
172
180
234
80
175
190
241
90
179
200
247
Table 1 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound temperatures for
the benchmark GMD event. Table 2 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound
temperatures for the supplemental GMD event.
5
Effective GIC in the table is the peak GIC(t) for the GMD event being assessed. Peak GIC(t) is not steady-state GIC.
4
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4
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC Metallic hot spot
Effective
Metallic hot spot
(A/phase)
Temperature (°C )
GIC(A/phase)
Temperature (°C )
0
80
120
188
10
107
130
191
20
124
140
194
30
137
150
198
40
147
160
203
50
156
170
209
60
161
180
214
70
162
190
229
75
165
200
237
80
169
220
248
85
172
230
253
90
177
250
276
100
181
275
298
110
185
300
316
Two different ways to carry out a detailed thermal impact assessment are discussed below. In addition,
other approaches and models approved by international standard-setting organizations such as the
Institute of Electrical and Electronic Engineers (IEEE) or International Council on Large Electric Systems
(CIGRE) may also provide technically justified methods for performing thermal assessments. 6 All thermal
assessment methods should be demonstrably equivalent to assessments that use the GMD events
associated with TPL-007-2.
1. Transformer manufacturer GIC capability curves. These curves relate permissible peak GIC
(obtained by the user from a steady-state GIC calculation) and loading, for a specific transformer.
An example of manufacturer capability curves is provided in Figure 2. Presentation details vary
between manufacturers, and limited information is available regarding the assumptions used to
generate these curves, in particular, the assumed waveshape or duration of the effective GIC.
Some manufacturers assume that the waveform of the GIC in the transformer windings is a square
pulse of 2, 10, or 30 minutes in duration. In the case of the transformer capability curve shown in
Figure 2, a square pulse of 900 A/phase with a duration of 2 minutes would cause the Flitch plate
hot spot to reach a temperature of 180°C at full load [5]. While GIC capability curves are relatively
simple to use, an amount of engineering judgment is necessary to ascertain which portion of a GIC
waveform is equivalent to, for example, a 2 minute pulse. Also, manufacturers generally maintain
that in the absence of transformer standards defining thermal duty due to GIC, such capability
curves must be developed for every transformer design and vintage.
6
For example, C57.163-2015 – IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances. [4]
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
5
100
Flitch Plate Temp = 180 C for 2 Minutes
90
Flitch Plate Temp = 160 C for 30 Minutes
% MVA Rating
80
70
60
50
40
30
600
800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000
GIC, Amps/Phase
Figure 2: Sample GIC Manufacturer Capability Curve of a Large Single-Phase Transformer
Design using the Flitch Plate Temperature Criteria [5]
2. Thermal response simulation.7 The input to this type of simulation is the time series or waveform
of effective GIC flowing through a transformer (taking into account the actual configuration of the
system), and the result of the simulation is the hot spot temperature (winding or metallic part)
time sequence for a given transformer. An example of GIC input and hotspot temperature time
series values from [6] are shown in Figure 3. The hot spot thermal transfer functions can be
obtained from measurements or calculations provided by transformer manufacturers.
Conservative default values can be used (e.g., those provided in [6]) when specific data are not
available. Hot spot temperature thresholds shown in Figure 3 are consistent with IEEE Std C57.912011 emergency loading hot spot limits. Emergency loading time limit is usually 30 minutes.
7
Technical details of this methodology can be found in [6].
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
6
Figure 3: Sample Tie Plate Temperature Calculation
Blue trace is incremental temperature and red trace is the magnitude of the GIC/phase [6]
It is important to reiterate that the characteristics of the time sequence or “waveform” are very important
in the assessment of the thermal impact of GIC on transformers. Transformer hot spot heating is not
instantaneous. The thermal time constants of transformer windings and metallic parts are typically on the
order of minutes to tens of minutes; therefore, hot spot temperatures are heavily dependent on GIC
history and rise time, amplitude and duration of GIC in the transformer windings, bulk oil temperature
due to loading, ambient temperature and cooling mode.
Calculation of the GIC Waveform for a Transformer
The following procedure can be used to generate time series GIC data (i.e., GIC(t)) using a software
program capable of computing GIC in the steady-state. The steps are as follows:
1. Calculate contribution of GIC due to eastward and northward geoelectric fields for the transformer
under consideration;
2. Scale the GIC contribution according to the reference geoelectric field time series to produce the
GIC time series for the transformer under consideration.
Most available GIC–capable software packages can calculate GIC in steady-state in a transformer assuming
a uniform eastward geoelectric field of 1 V/km (GICE) while the northward geoelectric field is zero. Similarly,
GICN can be obtained for a uniform northward geoelectric field of 1 V/km while the eastward geoelectric
field is zero. GICE and GICN are the normalized GIC contributions for the transformer under consideration.
If the earth conductivity is assumed to be uniform (or laterally uniform) in the transmission system of
interest, then the transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be calculated using (2)
[2].
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
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GIC (t ) = E (t ) ⋅ {GIC E sin(ϕ (t )) + GIC N cos(ϕ (t ))}
(2)
E (t ) = E N2 (t ) + E E2 (t )
(3)
where
E (t )
ϕ (t ) = tan −1 E
E N (t )
GIC (t ) = EE (t ) ⋅ GICE + EN (t ) ⋅ GICN
(4)
(5)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km)
The geoelectric field time series EN(t) and EE(t) is obtained, for instance, from the reference geomagnetic
field time series (from [7] and/or [8]) after the appropriate geomagnetic latitude scaling factor α is applied.8
The reference geoelectric field time series is calculated using the reference earth model. When using this
geoelectric field time series where a different earth model is applicable, it should be scaled with the
appropriate conductivity scaling factor β. 9 Alternatively, the geoelectric field can be calculated from the
reference geomagnetic field time series after the appropriate geomagnetic latitude scaling factor α is
applied and the appropriate earth model is used. In such case, the conductivity scaling factor β is not applied
because it is already accounted for by the use of the appropriate earth model.
Applying (5) to each point in EN(t) and EE(t) results in GIC(t).
GIC(t) Calculation Example
Let us assume that from the steady-state solution, the effective GIC in this transformer is GICE = -20 A/phase
if EN=0, EE=1 V/km and GICN = 26 A/phase if EN=1 V/km, EE=0. Let us also assume the geomagnetic field time
series corresponds to a geomagnetic latitude where α = 1 and that the earth conductivity corresponds to
the reference earth model in [7]. The resulting geoelectric field time series is shown in Figure 4. Therefore:
GIC (t ) = EE (t ) ⋅ GICE + EN (t ) ⋅ GICN (A/phase)
(6)
GIC (t ) = − E E (t ) ⋅ 20 + ⋅E N (t ) ⋅ 26 (A/phase)
(7)
The geomagnetic factor α is described in [2] and is used to scale the geomagnetic field according to geomagnetic latitude. The
lower the geomagnetic latitude (closer to the equator), the lower the amplitude of the geomagnetic field.
9
The conductivity scaling factor β is described in [2], and is used to scale the geoelectric field according to the conductivity of
different physiographic regions. Lower conductivity results in higher β scaling factors.
8
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The resulting GIC waveform GIC(t) is shown in Figures 5 and 6 and can subsequently be used for thermal
analysis.
It should be emphasized that even for the same reference event, the GIC(t) waveform in every transformer
will be different, depending on the location within the system and the number and orientation of the
circuits connecting to the transformer station. Assuming a single generic GIC(t) waveform to test all
transformers is incorrect.
Figure 4: Calculated Geoelectric Field EN(t) and EE(t) Assuming α=1 and β=1
(Reference Earth Model).
Zoom area for subsequent graphs is highlighted.
Dashed lines approximately show the close-up area for subsequent Figures.
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Figure 5: Calculated GIC(t) Assuming α=1 and β=1
Reference Earth Model
Figure 6: Calculated Magnitude of GIC(t) Assuming α=1 and β=1
Reference Earth Model
Transformer Thermal Assessment Examples
There are two basic ways to carry out a transformer thermal analysis once the GIC time series GIC(t) is
known for a given transformer: 1) calculating the thermal response as a function of time; and 2) using
manufacturer’s capability curves.
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Ex am ple 1: Calculating therm al response as a function of tim e using a therm al response tool
The thermal step response of the transformer can be obtained for both winding and metallic part hot
spots from: 1) measurements; 2) manufacturer’s calculations; or 3) generic published values. Figure 7
shows the measured metallic hot spot thermal response to a dc step of 16.67 A/phase of the top yoke
clamp from [9] that will be used in this example. Figure 8 shows the measured incremental temperature
rise (asymptotic response) of the same hot spot to long duration GIC steps. 10
Figure 7: Thermal Step Response to a 16.67 Amperes per Phase dc Step
Metallic hot spot heating
Figure 8: Asymptotic Thermal Step Response
Metallic hot spot heating
Heating of bulk oil due to the hot spot temperature increase is not included in the asymptotic response because the time constant
of bulk oil heating is at least an order of magnitude larger than the time constants of hot spot heating.
10
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The step response in Figure 7 was obtained from the first GIC step of the tests carried out in [6]. The
asymptotic thermal response in Figure 8 was obtained from the final or near-final temperature values
after each subsequent GIC step. Figure 9 shows a comparison between measured temperatures and the
calculated temperatures using the thermal response model used in the rest of this discussion.
Figure 9: Comparison of measured temperatures (red) and simulation results (blue).
Injected current is represented by magenta.
To obtain the thermal response of the transformer to a GIC waveform such as the one in Figure 6, a thermal
response model is required. To create a thermal response model, the measured or manufacturer-calculated
transformer thermal step responses (winding and metallic part) for various GIC levels are required. The
GIC(t) time series or waveform is then applied to the thermal model to obtain the incremental temperature
rise as a function of time θ(t) for the GIC(t) waveform. The total temperature is calculated by adding the oil
temperature, for example, at full load.
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Figure 10 illustrates the calculated GIC(t) and the corresponding metallic hot spot temperature time series
θ(t). Figure 11 illustrates a close-up view of the peak transformer temperatures calculated in this
example.
Figure 10: Magnitude of GIC(t) and Metallic Hot Spot Temperature θ(t) Assuming Full Load
Oil Temperature of 85.3°C (40°C ambient).
Dashed lines approximately show the close-up area for subsequent figures
Figure 11: Close-up of Metallic Hot Spot Temperature Assuming a Full Load
Blue trace is θ(t). Red trace is GIC(t)
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In this example, the IEEE Std C57.91-2011 emergency loading hot spot threshold of 200°C for metallic hot
spot heating is not exceeded. Peak temperature is 186°C. The IEEE standard is silent as to whether the
temperature can be higher than 200°C for less than 30 minutes. Manufacturers can provide guidance on
individual transformer capability.
It is not unusual to use a lower temperature threshold of 180°C to account for calculation and data margins,
as well as transformer age and condition. Figure 11 shows that 180°C will be exceeded for 5 minutes.
At 75% loading, the initial temperature is 64.6°C rather than 85.3°C, and the hot spot temperature peak is
165°C, well below the 180°C threshold (see Figure 12).
If a conservative threshold of 160°C were used to account for the age and condition of the transformer,
then the full load limits would be exceeded for approximately 22 minutes.
Figure 12: Close-up of Metallic Hot Spot Temperature Assuming a 75% Load
Oil temperature of 64.5°C
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Ex am ple 2: Using a M anufacturer’s Capability Curves
The capability curves used in this example are shown in Figure 13. To maintain consistency with the
previous example, these particular capability curves have been reconstructed from the thermal step
response shown in Figures 7 and 8, and the simplified loading curve shown in Figure 14 (calculated using
formulas from IEEE Std C57.91-2011).
Figure 13: Capability Curve of a Transformer Based on the Thermal Response Shown in
Figures 8 and 9.
Figure 14: Simplified Loading Curve Assuming 40°C Ambient Temperature.
The basic notion behind the use of capability curves is to compare the calculated GIC in a transformer with
the limits at different GIC pulse widths. A narrow GIC pulse has a higher limit than a longer duration or wider
one. If the calculated GIC and assumed pulse width falls below the appropriate pulse width curve, then the
transformer is within its capability.
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To use these curves, it is necessary to estimate an equivalent square pulse that matches the waveform of
GIC(t), generally at a GIC(t) peak. Figure 15 shows a close-up of the GIC near its highest peak
superimposed to a 255 Amperes per phase, 2 minute pulse at 100% loading from Figure 13. Since a
narrow 2-minute pulse is not representative of GIC(t) in this case, a 5 minute pulse with an amplitude of
180 A/phase at 100% loading has been superimposed on Figure 16. It should be noted that a 255 A/phase,
2 minute pulse is equivalent to a 180 A/phase 5 minute pulse from the point of view of transformer
capability. Deciding what GIC pulse is equivalent to the portion of GIC(t) under consideration is a matter
of engineering judgment.
Figure 15: Close-up of GIC(t) and a 2 minute 255 A/phase GIC pulse at full load
Figure 16: Close-up of GIC(t) and a Five Minute 180 A/phase GIC Pulse at Full Load
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When using a capability curve, it should be understood that the curve is derived assuming that there is no
hot spot heating due to prior GIC at the time the GIC pulse occurs (only an initial temperature due to
loading). Therefore, in addition to estimating the equivalent pulse that matches GIC(t), prior metallic hot
spot heating must be accounted for. From these considerations, it is unclear whether the capability curves
would be exceeded at full load with a 180°C threshold in this example.
At 70% loading, the two and five minute pulses from Figure 13 would have amplitudes of 310 and 225
A/phase, respectively. The 5 minute pulse is illustrated in Figure 17. In this case, judgment is also required
to assess if the GIC(t) is within the capability curve for 70% loading. In general, capability curves are easier
to use when GIC(t) is substantially above, or clearly below the GIC thresholds for a given pulse duration.
If a conservative threshold of 160°C were used to account for the age and condition of the transformer,
then a new set of capability curves would be required.
Figure 17: Close-up of GIC(t) and a 5 Minute 225 A/phase GIC Pulse Assuming 75% Load
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References
[1] "IEEE Guide for loading mineral-oil-immersed transformers and step-voltage regulators." IEEE Std
C57.91-2011 (Revision of IEEE Std C57.91-1995).
[2] Application Guide: Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC.
Available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%20
2013/GIC%20Application%20Guide%202013_approved.pdf
[3] “Screening Criterion for Transformer Thermal Impact Assessment”. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[4] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic
Disturbances.” IEEE Std C57.163-2015
[5] Girgis, R.; Vedante, K. “Methodology for evaluating the impact of GIC and GIC capability of power
transformer designs.” IEEE PES 2013 General Meeting Proceedings. Vancouver, Canada.
[6] Marti, L., Rezaei-Zare, A., Narang, A. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents." IEEE Transactions on Power Delivery, vol.28, no.1. pp 320327. January 2013.
[7] Benchmark Geomagnetic Disturbance Event Description white paper. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[8] Supplemental Geomagnetic Disturbance Event Description white paper. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
[9] Lahtinen, Matti. Jarmo Elovaara. “GIC occurrences and GIC test for 400 kV system transformer”.
IEEE Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
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Transformer Thermal Impact Assessment
White Paper
Project 2013-03 (Geomagnetic Disturbance Mitigation)
TPL-007-12 ̶ Transmission System Planned Performance for Geomagnetic
Disturbance Events
Background
On May 16, 2013, FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances (GMDs) in two stages:
• Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. EOP-010-1 – Geomagnetic Disturbance Operations was approved by FERC in June 2014.
• Stage 2 Standard(s) that require applicable entities to conduct assessments of the potential impact
of benchmark GMD events on their systems. If the assessments identify potential impacts, the
Standard(s) will require the applicable entity to develop and implement a plan to mitigate the risk.
TPL-007-1 is a new Reliability Standard to specifically address the Stage 2 directives in Order No. 779.
Large power transformers connected to the EHV transmission system can experience both winding and
structural hot spot heating as a result of GMD events. TPL-007-1 will require owners of such transformers
to conduct thermal analyses of their transformers to determine if the transformers will be able to withstand
the thermal transient effects associated with the Benchmark GMD event. This paper discusses methods
that can be employed to conduct such analyses, including example calculations.
Proposed TPL-007-2 includes requirements for entities to perform two types of GMD Vulnerability
Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
•
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL-007-1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially-averaged
geoelectric field values to address potential wide-area effects that could be caused by a severe 1-in100 year GMD event.1
•
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate localized peaks in geomagnetic field during a severe GMD event that "could
1
2016.
See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15-11 on June 28,
potentially affect the reliable operation of the Bulk-Power System."2 Localized enhancements of
geomagnetic field can result in geoelectric field values above the spatially-averaged benchmark in
a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye-grounded windings with terminal voltage greater than 200 kV. Large
power transformers connected to the EHV transmission system can experience both winding and structural
hot spot heating as a result of GMD events. TPL-007-2 requires owners of such BES transformers to conduct
thermal analyses to determine if the BES transformers will be able to withstand the thermal transient
effects associated with the GMD events. BES Transformers must undergo a thermal impact assessment if
the maximum effective geomagnetically-induced current (GIC) in the transformer is equal to or greater
than: 3
•
•
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
This white paper discusses methods that can be employed to conduct transformer thermal impact
assessments, including example calculations. The first version of the white paper was developed by the
Project 2013-03 GMD Standards Drafting Team (SDT) for TPL-007-1 and was endorsed by the Electric
Reliability Organization (ERO) as implementation guidance in October 2016. The SDT has updated the white
paper to include the supplemental GMD event that is added in TPL-007-2 to address directives in FERC
Order No. 830.
The primary impact of GMDs on large power transformers is a result of the quasi-dc current that flows
through wye-grounded transformer windings. This geomagnetically-induced current (GIC) results in an
offset of the ac sinusoidal flux resulting in asymmetric or half-cycle saturation (see Figure 1).
Half-cycle saturation results in a number of known effects:
• Hot spot heating of transformer windings due to harmonics and stray flux;
• Hot spot heating of non-current carrying transformer metallic members due to stray flux;
• Harmonics;
• Increase in reactive power absorption; and
• Increase in vibration and noise level.
See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event,
included in TPL-007-1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for
this assessment are in the Supplemental GMD Event Description white paper.
3
See Screening Criterion for Transformer Thermal Impact Assessment for technical justification.
2
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2
λ
λdc
λ
Lair-core
λm
Lu
θ
o
π/2
im
o
o
im
π
GIC
Vm
− π/2
θ = ωt
θ
ibias
Figure 1: Mapping Magnetization Current to Flux through Core Excitation Characteristics
This paper focuses on hot spot heating of transformer windings and non current-carrying metallic parts.
Effects such as the generation of harmonics, increase in reactive power absorption, vibration, and noise
are not within the scope of this document.
Technical Considerations
The effects of half-cycle saturation on HV and EHV transformers, namely localized “hot spot” heating, are
relatively well understood, but are difficult to quantify. A transformer GMD impact assessment must
consider GIC amplitude, duration, and transformer physical characteristics such as design and condition
(e.g., age, gas content, and moisture in the oil). A single threshold value of GIC cannot be justified as a “pass
or fail” screening criterion where “fail” means that the transformer will suffer damage. A single threshold
value of GIC only makes sense in the context where “fail” means that a more detailed study is required and
that “pass” means that GIC in a particular transformer is so low that a detailed study is unnecessary.. Such
a threshold would have to be technically justifiable and sufficiently low to be considered a conservative
value within the scope of the benchmark.of GIC.
The following considerations should be taken into account when assessing the thermal susceptibility of a
transformer to half-cycle saturation:
•
In the absence of manufacturer specific information, use the temperature limits for safe transformer
operation such as those suggested in the IEEE Std C57.91-2011 standard [1](IEEE Guide for Loading
Mineral-oil-immersed Transformers and Step-voltage Regulators) for hot spot heating during short-
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3
term emergency operation. [1]. This standard does not suggest that exceeding these limits will result
in transformer failure, but rather that it will result in additional aging of cellulose in the paper-oil
insulation and the potential for the generation of gas bubbles in the bulk oil. Thus, from the point
of view of evaluating possible transformer damage due to increased hot spot heating, these
thresholds can be considered conservative for a transformer in good operational condition.
•
The worst case temperature rise for winding and metallic part (e.g., tie plate) heating should be
estimated taking into consideration the construction characteristics of the transformer as they
pertain to dc flux offset in the core (e.g., single-phase, shell, 5 and 3-leg three-phase construction).
•
Bulk oil temperature due to ambient temperature and transformer loading must be added to the
incremental temperature rise caused by hot spot heating. For planning purposes, maximum ambient
and loading temperature should be used unless there is a technically justified reason to do
otherwise.
•
The time series or “waveshapewaveform” of the reference GMD event in terms of peak amplitude,
duration, and frequency of the geoelectric field has an important effect on hot spot heating. Winding
and metallic part hot spot heating have different thermal time constants, and their temperature rise
will be different if the GIC currents are sustained for 2, 10, or 30 minutes for a given GIC peak
amplitude.
•
The “effective” GIC in autotransformers (reflecting the different GIC ampere-turns in the common
and the series windings) must be used in the assessment. The effective current Idc,eq in an
autotransformer is defined by [2].
I dc ,eq = I H + ( I N / 3 − I H )V X / VH
(1)
where
IH is the dc current in the high voltage winding;
IN is the neutral dc current;
VH is the rms rated voltage at HV terminals;
VX is the rms rated voltage at the LV terminals.
Transformer Thermal Impact Assessment Process
A simplified thermal assessment may be based on Table 2the appropriate tables from the “Screening
Criterion for Transformer Thermal Impact Assessment” white paper [7]. This3].4 Each table, shown as
Table 1 below, provides the peak metallic hot spot temperatures that can be reached for the given GMD
event using conservative thermal models. To use Table 1each table, one must select the bulk oil
temperature and the threshold for metallic hot spot heating, for instance, from reference [1] after
Table 1 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound temperatures for
the benchmark GMD event. Table 2 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound
temperatures for the supplemental GMD event.
4
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4
allowing for possible de-rating due to transformer condition. If the effective GIC results in higher than
threshold temperatures, then the use of a detailed thermal assessment as described below should be
carried out.5
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
Temperature (°C )
(A/phase)
Temperature (°C )
0
80
100
182
10
107
110
186
20
128
120
190
30
139
130
193
40
148
140
204
50
157
150
213
60
169
160
221
70
170
170
230
75
172
180
234
80
175
190
241
90
179
200
247
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC Metallic hot spot
Effective
Metallic hot spot
(A/phase)
Temperature (°C )
GIC(A/phase)
Temperature (°C )
0
80
120
188
10
107
130
191
20
124
140
194
30
137
150
198
40
147
160
203
50
156
170
209
60
161
180
214
70
162
190
229
75
165
200
237
80
169
220
248
85
172
230
253
5
Effective GIC in the table is the peak GIC(t) for the GMD event being assessed. Peak GIC(t) is not steady-state GIC.
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5
90
100
110
177
181
185
250
275
300
276
298
316
Two different ways to carry out a detailed thermal impact assessment are discussed below. In addition,
other approaches and models approved by international standard-setting organizations such as the
Institute of Electrical and Electronic Engineers (IEEE) or International Council on Large Electric Systems
(CIGRE) may also provide technically justified methods for performing thermal assessments. 6 All thermal
assessment methods should be demonstrably equivalent to assessments that use the benchmark GMD
event.GMD events associated with TPL-007-2.
1. Transformer manufacturer GIC capability curves. These curves relate permissible peak GIC
(obtained by the user from a steady-state GIC calculation) and loading, for a specific transformer.
An example of manufacturer capability curves is provided in Figure 2. Presentation details vary
between manufacturers, and limited information is available regarding the assumptions used to
generate these curves, in particular, the assumed waveshape or duration of the effective GIC.
Some manufacturers assume that the waveshapewaveform of the GIC in the transformer windings
is a square pulse of 2, 10, or 30 minutes in duration. In the case of the transformer capability curve
shown in Figure 2 [3],, a square pulse of 900 A/phase with a duration of 2 minutes would cause
the Flitch plate hot spot to reach a temperature of 180 °°C at full load. [5]. While GIC capability
curves are relatively simple to use, an amount of engineering judgment is necessary to ascertain
which portion of a GIC waveshapewaveform is equivalent to, for example, a 2 minute pulse. Also,
manufacturers generally maintain that in the absence of transformer standards defining thermal
duty due to GIC, such capability curves must be developed for every transformer design and
vintage.
6
For example, C57.163-2015 – IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances. [4]
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6
100
Flitch Plate Temp = 180 C for 2 Minutes
90
Flitch Plate Temp = 160 C for 30 Minutes
% MVA Rating
80
70
60
50
40
30
600
800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000
GIC, Amps/Phase
Figure 2: Sample GIC Manufacturer Capability Curve of a Large Single-Phase Transformer
Design using the Flitch Plate Temperature Criteria [35]
2. Thermal response simulation.7. The input to this type of simulation is the time series or
waveshapewaveform of effective GIC flowing through a transformer (taking into account the
actual configuration of the system), and the result of the simulation is the hot spot temperature
(winding or metallic part) time sequence for a given transformer. An example of GIC input and
hotspot temperature time series values from [46] are shown in Figure 3. The hot spot thermal
transfer functions can be obtained from measurements or calculations provided by transformer
manufacturers. Conservative default values can be used (e.g.., those provided in [46]) when
specific data are not available. Hot spot temperature thresholds shown in Figure 3 are consistent
with IEEE Std C57.91-2011 emergency loading hot spot limits. Emergency loading time limit is
usually 30 minutes.
7
Technical details of this methodology can be found in [46].
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GIC
Figure 3: Sample Tie Plate Temperature Calculation
Blue trace is incremental temperature and red trace is the magnitude of the GIC/phase [4] 6]
It is important to reiterate that the characteristics of the time sequence or “waveshapewaveform” are
very important in the assessment of the thermal impact of GIC on transformers. Transformer hot spot
heating is not instantaneous. The thermal time constants of transformer windings and metallic parts are
typically on the order of minutes to tens of minutes; therefore, hot spot temperatures are heavily
dependent on GIC history and rise time, amplitude and duration of GIC in the transformer windings, bulk
oil temperature due to loading, ambient temperature and cooling mode.
Calculation of the GIC WaveshapeWaveform for a Transformer
The following procedure can be used to generate time series GIC data, (i.e.., GIC(t),)) using a software
program capable of computing GIC in the steady-state. The steps are as follows:
1. Calculate contribution of GIC due to eastward and northward geoelectric fields for the transformer
under consideration;
2. Scale the GIC contribution according to the reference geoelectric field time series to produce the
GIC time series for the transformer under consideration.
Most available GIC–capable software packages can calculate GIC in steady-state in a transformer assuming
a uniform eastward geoelectric field of 1 V/km (GICE) while the northward geoelectric field is zero. Similarly,
GICN can be obtained for a uniform northward geoelectric field of 1 V/km while the eastward geoelectric
field is zero. GICE and GICN are the normalized GIC contributions for the transformer under consideration.
If the earth conductivity is assumed to be uniform (or laterally uniform) in the transmission system of
interest, then the transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be calculated using (2)
[2].
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GIC (t ) = E (t ) ⋅ {GIC E sin(ϕ (t )) + GIC N cos(ϕ (t ))}
(2)
E (t ) = E N2 (t ) + E E2 (t )
(3)
where
E E (t )
(
)
E
t
N
ϕ (t ) = tan −1
GIC (t ) = EE (t ) ⋅ GICE + E N (t ) ⋅ GICN
(4)
(5)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase/ per V/km)
The geoelectric field time series EN(t) and EE(t) is obtained, for instance, from the reference geomagnetic
field time series [5](from [7] and/or [8]) after the appropriate geomagnetic latitude scaling factor α is
applied. 8. The reference geoelectric field time series is calculated using the reference earth model. When
using this geoelectric field time series where a different earth model is applicable, it should be scaled with
the appropriate conductivity scaling factor ββ.9. Alternatively, the geoelectric field can be calculated from
the reference geomagnetic field time series after the appropriate geomagnetic latitude scaling factor α is
applied and the appropriate earth model is used. In such case, the conductivity scaling factor β is not applied
because it is already accounted for by the use of the appropriate earth model.
Applying (5) to each point in EN(t) and EE(t) results in GIC(t).
GIC(t) Calculation Example
Let us assume that from the steady-state solution, the effective GIC in this transformer is GICE = -20 A/phase
if EN=0, EE=1 V/km and GICN = 26 A/phase if EN=1 V/km, EE=0. Let us also assume the geomagnetic field time
series corresponds to a geomagnetic latitude where α = 1 and that the earth conductivity corresponds to
the reference earth model in [57]. The resulting geoelectric field time series is shown in Figure 4. Therefore:
GIC (t ) = EE (t ) ⋅ GICE + E N (t ) ⋅ GICN (A/phase)
(6)
GIC (t ) = − E E (t ) ⋅ 20 + ⋅E N (t ) ⋅ 26 (A/phase)
(7)
The geomagnetic factor α is described in [2] and is used to scale the geomagnetic field according to geomagnetic latitude. The
lower the geomagnetic latitude (closer to the equator), the lower the amplitude of the geomagnetic field.
9
The conductivity scaling factor β is described in [2], and is used to scale the geoelectric field according to the conductivity of
different physiographic regions. Lower conductivity results in higher β scaling factors.
8
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The resulting GIC waveshapewaveform GIC(t) is shown in Figures 5 and 6 and can subsequently be used for
thermal analysis.
It should be emphasized that even for the same reference event, the GIC(t) waveshapewaveform in every
transformer will be different, depending on the location within the system and the number and orientation
of the circuits connecting to the transformer station. Assuming a single generic GIC(t) waveshapewaveform
to test all transformers is incorrect.
Figure 4: Calculated Geoelectric Field EN(t) and EE(t) Assuming α=1 and β=1
(Reference Earth Model).
Zoom area for subsequent graphs is highlighted.
Dashed lines approximately show the close-up area for subsequent Figures.
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Figure 5: Calculated GIC(t) Assuming α=1 and β=1
(Reference Earth Model)
Figure 6: Calculated Magnitude of GIC(t) Assuming α=1 and β=1
(Reference Earth Model)
Transformer Thermal Assessment Examples
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There are two basic ways to carry out a transformer thermal analysis once the GIC time series GIC(t) is
known for a given transformer: 1) calculating the thermal response as a function of time; and 2) using
manufacturer’s capability curves.
Ex am ple 1: Calculating therm al response as a function of tim e using a therm al response tool
The thermal step response of the transformer can be obtained for both winding and metallic part hot
spots from: 1) measurements; 2) manufacturer’s calculations; or 3) generic published values. Figure 7
shows the measured metallic hot spot thermal response to a dc step of 16.67 A/phase of the top yoke
clamp from [69] that will be used in this example. Figure 8 shows the measured incremental temperature
rise (asymptotic response) of the same hot spot to long duration GIC steps. 10
Figure 7: Thermal Step Response to a 16.67 Amperes per Phase dc Step
Metallic hot spot heating.
Heating of bulk oil due to the hot spot temperature increase is not included in the asymptotic response because the time constant
of bulk oil heating is at least an order of magnitude larger than the time constants of hot spot heating.
10
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Figure 8: Asymptotic Thermal Step Response
Metallic hot spot heating.
The step response in Figure 7 was obtained from the first GIC step of the tests carried out in [6]. The
asymptotic thermal response in Figure 8 was obtained from the final or near-final temperature values
after each subsequent GIC step. Figure 9 shows a comparison between measured temperatures and the
calculated temperatures using the thermal response model used in the rest of this discussion.
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Figure 9: Comparison of measured temperatures (red trace) and simulation results (blue
trace). ).
Injected current is represented by the magenta trace.
To obtain the thermal response of the transformer to a GIC waveshapewaveform such as the one in Figure
6, a thermal response model is required. To create a thermal response model, the measured or
manufacturer-calculated transformer thermal step responses (winding and metallic part) for various GIC
levels are required. The GIC(t) time series or waveshapewaveform is then applied to the thermal model to
obtain the incremental temperature rise as a function of time θ(t) for the GIC(t) waveshapewaveform. The
total temperature is calculated by adding the oil temperature, for example, at full load.
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | May 2016
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Figure 10 illustrates the calculated GIC(t) and the corresponding metallic hot spot temperature time series
θ(t). Figure 11 illustrates a close-up view of the peak transformer temperatures calculated in this
example.
Figure 10: Magnitude of GIC(t) and Metallic Hot Spot Temperature θ(t) Assuming Full Load
Oil Temperature of 85.3°C (40°C ambient). Dashed lines approximately show the close-up
area for subsequent Figures.
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Figure 11: Close-up of Metallic Hot Spot Temperature Assuming a Full Load
(Blue trace is θ(t). Red trace is GIC(t)))
In this example, the IEEE Std C57.91-2011 emergency loading hot spot threshold of 200°C for metallic hot
spot heating is not exceeded. Peak temperature is 186°C. The IEEE standard is silent as to whether the
temperature can be higher than 200°C for less than 30 minutes. Manufacturers can provide guidance on
individual transformer capability.
It is not unusual to use a lower temperature threshold of 180°C to account for calculation and data margins,
as well as transformer age and condition. Figure 11 shows that 180°C will be exceeded for 5 minutes.
At 75% loading, the initial temperature is 64.6 °°C rather than 85.3 °°C, and the hot spot temperature peak
is 165°C, well below the 180°C threshold (see Figure 12).
If a conservative threshold of 160°C were used to account for the age and condition of the transformer,
then the full load limits would be exceeded for approximately 22 minutes.
Figure 12: Close-up of Metallic Hot Spot Temperature Assuming a 75% Load
(Oil temperature of 64.5°C)
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | May 2016
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Ex am ple 2: Using a M anufacturer’s Capability Curves
The capability curves used in this example are shown in Figure 13. To maintain consistency with the
previous example, these particular capability curves have been reconstructed from the thermal step
response shown in Figures 7 and 8, and the simplified loading curve shown in Figure 14 (calculated using
formulas from IEEE Std C57.91). -2011).
Figure 13: Capability Curve of a Transformer Based on the Thermal Response Shown in
Figures 8 and 9.
Figure 14: Simplified Loading Curve Assuming 40°C Ambient Temperature.
The basic notion behind the use of capability curves is to compare the calculated GIC in a transformer with
the limits at different GIC pulse widths. A narrow GIC pulse has a higher limit than a longer duration or wider
one. If the calculated GIC and assumed pulse width falls below the appropriate pulse width curve, then the
transformer is within its capability.
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To use these curves, it is necessary to estimate an equivalent square pulse that matches the
waveshapewaveform of GIC(t), generally at a GIC(t) peak. Figure 15 shows a close-up of the GIC near its
highest peak superimposed to a 255 Amperes per phase, 2 minute pulse at 100% loading from Figure 13.
Since a narrow 2-minute pulse is not representative of GIC(t) in this case, a 5 minute pulse with an
amplitude of 180 A/phase at 100% loading has been superimposed on Figure 16. It should be noted that a
255 A/phase, 2 minute pulse is equivalent to a 180 A/phase 5 minute pulse from the point of view of
transformer capability. Deciding what GIC pulse is equivalent to the portion of GIC(t) under consideration
is a matter of engineering judgment.
Figure 15: Close-up of GIC(t) and a 2 minute 255 A/phase GIC pulse at full load
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | May 2016
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Figure 16: Close-up of GIC(t) and a Five Minute 180 A/phase GIC Pulse at Full Load
When using a capability curve, it should be understood that the curve is derived assuming that there is no
hot spot heating due to prior GIC at the time the GIC pulse occurs (only an initial temperature due to
loading). Therefore, in addition to estimating the equivalent pulse that matches GIC(t), prior metallic hot
spot heating must be accounted for. From these considerations, it is unclear whether the capability curves
would be exceeded at full load with a 180 °°C threshold in this example.
At 70% loading, the two and five minute pulses from Figure 13 would have amplitudes of 310 and 225
A/phase, respectively. The 5 minute pulse is illustrated in Figure 17. In this case, judgment is also required
to assess if the GIC(t) is within the capability curve for 70% loading. In general, capability curves are easier
to use when GIC(t) is substantially above, or clearly below the GIC thresholds for a given pulse duration.
If a conservative threshold of 160°C were used to account for the age and condition of the transformer,
then a new set of capability curves would be required.
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Figure 17: Close-up of GIC(t) and a 5 Minute 225 A/phase GIC Pulse Assuming 75% Load
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | May 2016
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References
[1] "IEEE Guide for loading mineral-oil-immersed transformers and step-voltage regulators." IEEE Std
C57.91-2011 (Revision of IEEE Std C57.91-1995).
[2] Application Guide: Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC.
Available at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%20
2013/GIC%20Application%20Guide%202013_approved.pdf
[3] “Screening Criterion for Transformer Thermal Impact Assessment”. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[4] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic
Disturbances.” IEEE Std C57.163-2015
[3][5] Girgis, R.; Vedante, K. “Methodology for evaluating the impact of GIC and GIC capability of power
transformer designs.” IEEE PES 2013 General Meeting Proceedings. Vancouver, Canada.
[4][6] Marti, L., Rezaei-Zare, A., Narang, A. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents." IEEE Transactions on Power Delivery, vol.28, no.1. pp 320327. January 2013.
[5][7] Benchmark Geomagnetic Disturbance Event Description white paper. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[8] Supplemental Geomagnetic Disturbance Event Description white paper. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
[6][9] Lahtinen, Matti. Jarmo Elovaara. “GIC occurrences and GIC test for 400 kV system transformer”.
IEEE Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
[7][1] “Screening Criterion for Transformer Thermal Impact Assessment”. Developed by the Project
2013-03 (Geomagnetic Disturbance) standard drafting team. Available at:
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx
Transformer Thermal Impact Assessment: Project 2013-03 Geomagnetic Disturbance Mitigation | May 2016
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21
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation
DO NOT use this form for submitting comments. Use the electronic form to submit comments on
proposed TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events.
The electronic comment form must be completed by 8:00 p.m. Eastern, Friday, August 11, 2017.
Documents and information about this project are available on the project page. If you have any
questions, contact Standards Developer, Mark Olson (via email), or at (404) 446-9760.
Background Information
On September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830 approving
Reliability Standard TPL-007-1 − Transmission System Planned Performance for Geomagnetic Disturbance
Events. In the order, FERC directed NERC to develop certain modifications to the Standard, including:
•
•
•
•
Modify the benchmark geomagnetic disturbance (GMD) event definition used for GMD
Vulnerability Assessments;
Make related modifications to requirements pertaining to transformer thermal impact
assessments;
Require collection of GMD-related data; and
Require deadlines for Corrective Action Plans (CAPs) and GMD mitigating actions.
FERC established a deadline of 18 months from the effective date of Order No. 830 for completing the
revisions, which is May 2018.
The standard drafting team (SDT) has developed proposed TPL-007-2 to address the above directives.
Questions
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
1. The SDT developed proposed Requirements R8 – R10 and the supplemental GMD event to address
FERC concerns with the benchmark GMD event used in GMD Vulnerability Assessments. (Order No. 830
P.44, P.47-49, P.65). The requirements will obligate responsible entities to perform a supplemental GMD
Vulnerability Assessment based on the supplemental GMD event that accounts for potential impacts of
localized peak geoelectric fields. Do you agree with the proposed requirements? If you do not agree, or if
you agree but have comments or suggestions for the proposed requirements provide your
recommendation and explanation.
Yes
No
Comments:
2. The SDT developed the Supplemental GMD Event Description white paper to provide technical
justification for the supplemental GMD event. The purpose of the supplemental GMD event description is
to provide a defined event for assessing system performance for a GMD event which includes a local
enhancement of the geomagnetic field. Do you agree with the proposed supplemental GMD event and
the description in the white paper? If you do not agree, or if you agree but have comments or suggestions
for the supplemental GMD event and the description in the white paper provide your recommendation
and explanation.
Yes
No
Comments:
3. The SDT established an 85 A per phase screening criterion for determining which power transformers
are required to be assessed for thermal impacts from a supplemental GMD event in Requirement R10.
Justification for this threshold is provided in the revised Screening Criterion for Transformer Thermal
Impact Assessment white paper. Do you agree with the proposed 85 A per phase screening criterion and
the technical justification for this criterion that has been added to the white paper? If you do not agree, or
if you agree but have comments or suggestions for the screening criterion and revisions to the white
paper provide your recommendation and explanation.
Yes
No
Comments:
4. The SDT revised the Transformer Thermal Impact Assessment white paper to include the supplemental
GMD event. Do you agree with the revisions to the white paper? If you do not agree, or if you agree but
have comments or suggestions on the revisions to the white paper provide your recommendation and
explanation.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
2
5. The SDT developed proposed Requirement R7 to address FERC directives in Order No. 830 for
establishing Corrective Action Plan (CAP) deadlines associated with GMD Vulnerability Assessments (P.
101, 102). Do you agree with the proposed requirement? If you do not agree, or if you agree but have
comments or suggestions for the proposed requirement provide your recommendation and explanation.
Yes
No
Comments:
6. The SDT developed Requirements R11 and R12 to address FERC directives in Order No. 830 for
requiring responsible entities to collect GIC monitoring and magnetometer data (P. 88; P. 90-92). Do you
agree with the proposed requirements? If you do not agree, or if you agree but have comments or
suggestions for the proposed requirements provide your recommendation and explanation.
Yes
No
Comments:
7. Do you agree with the proposed Implementation Plan for TPL-007-2? If you do not agree, or if you
agree but have comments or suggestions for the Implementation Plan provide your recommendation and
explanation.
Yes
No
Comments:
8. Do you agree with the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for the
requirements in proposed TPL-007-2? If you do not agree, or if you agree but have comments or
suggestions for the VRFs and VSLs provide your recommendation and explanation.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
3
9. The SDT believes proposed TPL-007-2 provide entities with flexibility to meet the reliability objectives in
the project Standards Authorization Request (SAR) in a cost effective manner. Do you agree? If you do not
agree, or if you agree but have suggestions for improvement to enable additional cost effective
approaches to meet the reliability objectives, please provide your recommendation and, if appropriate,
technical justification.
Yes
No
Comments:
10. Provide any additional comments for the SDT to consider, if desired.
Comments:
Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation | June 2017
4
Violation Risk Factor and Violation Severity Level
Justifications
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
This document provides the Standard Drafting Team’s (SDT) justification for assignment of Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs) for each requirement in TPL-007-2 – Transmission System Planned Performance for Geomagnetic Disturbance Events.
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 ERO Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project.
NERC Criteria - 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 Violation Risk Factor Guidelines
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
The Commission 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
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
2
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
Guideline (2) – Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
The Commission 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.
NERC Criteria - 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.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
3
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
FERC’s 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.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
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 Justifications – TPL-007-2, R1
Proposed VRF
Low
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report. N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard. The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Lower is consistent with Reliability
Standard TPL-001-4 Requirement R7, which requires the Planning Coordinator, in conjunction with
each of its Transmission Planners, to identify each entity’s individual and joint responsibilities for
performing required studies for the Planning Assessment. Proposed TPL-007-2 Requirement R1
requires Planning Coordinators, in conjunction with Transmission Planners, to identify individual and
joint responsibilities for maintaining models and performing studies needed to complete the
benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in the Standard.
Guideline 4- Consistency with NERC Definitions of VRFs. A VRF of Lower is consistent with the NERC
VRF definition. The requirement for identifying individual and joint responsibilities of the Planning
Coordinator and each of the Transmission Planners in the Planning Coordinator’s planning area for
maintaining models, performing GMD studies, and obtaining GMD measurement data, 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, control, or restore the Bulk Electric System under conditions of a
GMD event.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
5
VRF Justifications – TPL-007-2, R1
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. The requirement
contains one objective, therefore a single VRF is assigned.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
6
Proposed VSLs – TPL-007-2, R1
Lower
N/A
Moderate
N/A
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
N/A
Severe
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 the Standard.
7
VSL Justifications – TPL-007-2, R1
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non-compliance.
The VSL is not changed in TPL-007-2.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL is worded consistently with the corresponding requirement.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
8
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
9
VRF Justifications – TPL-007-2, R2
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of High is consistent with the VRF for
Reliability Standard TPL-001-4 Requirement R1 as amended in NERC's filing dated August 29, 2014,
which requires Transmission Planners and Planning Coordinators to maintain models within its
respective planning area for performing studies needed to complete its Planning Assessment.
Proposed TPL-007-2, Requirement R2 requires responsible entities to maintain System models and GIC
System models of the responsible entity’s planning area for performing the studies needed to
complete benchmark and supplemental GMD Vulnerability Assessments.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. The System Models and GIC System Models serve as the foundation for all conditions
and events that are required to be studied and evaluated in the benchmark and supplemental GMD
Vulnerability Assessments. For this reason, failure to maintain models of the responsible entity’s
planning area for performing GMD studies could, under GMD conditions that are as severe as the
benchmark and supplemental GMD event, place the Bulk Electric System at an unacceptable risk of
instability, separation, or cascading failures.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
10
Proposed VSLs – TPL-007-2, R2
Lower
N/A
Moderate
N/A
High
Severe
The responsible entity did not
maintain either System models
or GIC System models of the
responsible entity’s planning
area for performing the study or
studies or studies needed to
complete benchmark and
supplemental GMD Vulnerability
Assessments.
The responsible entity did not
maintain both System models
and GIC System models of the
responsible entity’s planning
area for performing the study or
studies or studies needed to
complete benchmark and
supplemental GMD Vulnerability
Assessments.
VSL Justifications – TPL-007-2, R2
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Two VSLs are specified for a graduated scale.
The VSL is not changed in TPL-007-2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
11
VSL Justifications – TPL-007-2, R2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
12
VRF Justifications – TPL-007-2, R3
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard TPL-001-4 Requirement R5 which requires Transmission Planners and Planning Coordinators
to have criteria for acceptable System steady state voltage limits. Proposed TPL-007-2 Requirement R4
requires responsible entities to have criteria for acceptable System steady state voltage performance
for its System during the benchmark GMD event; these criteria may be different from the voltage
limits determined in Reliability Standard TPL-001-4 Requirement R5.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to have criteria for acceptable System steady state voltage limits for its
System during a GMD planning event could 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 during an actual GMD event. However, it is unlikely that such a failure by itself would
lead to Bulk Electric System instability, separation, or cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R3
Lower
N/A
Moderate
N/A
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
N/A
Severe
The responsible entity did not
have criteria for acceptable
13
Proposed VSLs – TPL-007-2, R3
System steady state voltage
performance for its System
during the GMD events
described in Attachment 1 as
required.
VSL Justifications – TPL-007-2, R3
NERC VSL Guidelines
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
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non-compliance.
The VSL is not changed in TPL-007-2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
14
VSL Justifications – TPL-007-2, R3
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
15
VRF Justifications – TPL-007-2, R4
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL-001-4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. Proposed TPL-007-2 Requirement R4 requires responsible entities to complete a
benchmark GMD Vulnerability Assessment to ensure the system meets performance criteria during the
benchmark GMD event.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a benchmark GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the benchmark GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R4
Lower
Moderate
The responsible entity
completed a benchmark GMD
Vulnerability Assessment, but it
was more than 60 calendar
The responsible entity's
completed benchmark GMD
Vulnerability Assessment failed
to satisfy one of elements listed
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
The responsible entity's
completed benchmark GMD
Vulnerability Assessment failed
to satisfy two of the elements
Severe
The responsible entity's
completed benchmark GMD
Vulnerability Assessment failed
to satisfy three of the elements
16
Proposed VSLs – TPL-007-2, R4
months and less than or equal
to 64 calendar months since the
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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 GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed benchmark
GMD Vulnerability Assessment.
VSL Justifications – TPL-007-2, R4
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL-007-2.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
17
VSL Justifications – TPL-007-2, R4
Lowering the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
The proposed VSL is not based on a cumulative number of violations.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
18
VSL Justifications – TPL-007-2, R4
Cumulative Number of
Violations
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
19
VRF Justifications – TPL-007-2, R5
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard MOD-032-1 Requirement R2 which requires applicable entities to provide modeling data to
Transmission Planners and Planning Coordinators. A VRF of Medium is also consistent with Reliability
Standard IRO-010-2 Requirement R3 which requires entities to provide data necessary for the
Reliability Coordinator to perform its Operational Planning Analysis and Real-time Assessments.
Proposed TPL-007-2 Requirement R5 requires responsible entities to provide specific geomagneticallyinduced currents (GIC) flow information to Transmission Owners and Generator Owners for
performing transformer thermal impact assessments.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the benchmark GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
20
Proposed VSLs – TPL-007-2, R5
Lower
Moderate
High
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.
Severe
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.
VSL Justifications – TPL-007-2, R5
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VLS is not changed in TPL-007-2.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
21
VSL Justifications – TPL-007-2, R5
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
22
VRF Justifications – TPL-007-2, R6
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard FAC-008-3 Requirement R6 which requires Transmission Owners and Generator Owners to
have Facility Ratings for all solely and jointly owned Facilities that are consistent with the associated
Facility Ratings methodology or documentation. Proposed TPL-007-2 Requirement R6 requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a benchmark transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
23
Proposed VSLs – TPL-007-2, R6
Lower
Moderate
High
Severe
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 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
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 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
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 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
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 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;
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
24
Proposed VSLs – TPL-007-2, R6
of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed to
include one of the required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed to
include two of the required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
OR
The responsible entity failed to
include three of the required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
VSL Justifications – TPL-007-2, R6
NERC VSL Guidelines
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL-007-2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
25
VSL Justifications – TPL-007-2, R6
Uniformity and Consistency in
the Determination of Penalties
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
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
26
VRF Justifications – TPL-007-2, R7
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. 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. Proposed TPL-007-2 Requirement R7 requires responsible entities to develop a Corrective
Action Plan when results of the benchmark GMD Vulnerability Assessment indicate that the System
does not meet performance requirements. While Reliability Standard TPL-001-4 has a single
requirement for performing the Planning Assessment and developing the Corrective Action Plan,
proposed TPL-007-2 has split the requirements for performing a benchmark GMD Vulnerability
Assessment and developing the Corrective Action Plan into two separate requirements because the
transformer thermal impact assessments performed by Transmission Owners and Generator Owners
must be considered. The sequencing with separate requirements follows a logical flow of the GMD
Vulnerability Assessment process.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to develop a Corrective Action Plan that addresses issues identified in a GMD
Vulnerability Assessment could, under GMD conditions that are as severe as the benchmark GMD
event, place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading
failures.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
27
Proposed VSLs – TPL-007-2, R7
Lower
The responsible entity's
Corrective Action Plan failed to
comply with one of the
elements in Requirement R7,
Parts 7.1 through 7.5.
Moderate
The responsible entity's
Corrective Action Plan failed to
comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
High
The responsible entity's
Corrective Action Plan failed to
comply with three of the
elements in Requirement R7,
Parts 7.1 through 7.5.
Severe
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
have a Corrective Action Plan as
required by Requirement R7.
VSL Justifications – TPL-007-2, R7
NERC VSL Guidelines
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The proposed requirement is a significant revision to TPL-007-2 to address the directive for Corrective
Action Plan deadlines contained in FERC Order No. 830. There is no prior compliance obligation
related to the directive. However, the requirement uses the same construct for a graduated scale as
TPL-007-1 Requirement R7 and is similar to Reliability Standard TPL-001-4, Requirement R2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
28
VSL Justifications – TPL-007-2, R7
Uniformity and Consistency in
the Determination of Penalties
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
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
29
VRF Justifications – TPL-007-2, R8
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL-001-4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. The proposed requirement is also consistent with approved TPL-007-1
Requirement R4 (unchanged in proposed TPL-007-2 Requirement R4). Proposed TPL-007-2
Requirement R8 requires responsible entities to complete a supplemental GMD Vulnerability
Assessment to assess system performance during a supplemental GMD event.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a supplemental GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the supplemental GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures by precluding responsible entities
from considering actions to mitigate risk of Cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R8
Lower
The responsible entity
completed a supplemental GMD
Moderate
The responsible entity's
completed supplemental GMD
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
The responsible entity's
completed supplemental GMD
Severe
The responsible entity's
completed supplemental GMD
30
Proposed VSLs – TPL-007-2, R8
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;
OR
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;
Vulnerability Assessment failed
to satisfy two 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 than 64 calendar
months and less than or equal
to 68 calendar months since the
last supplemental GMD
Vulnerability Assessment.
Vulnerability Assessment failed
to satisfy three of the 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 than 68 calendar
months and less than or equal
to 72 calendar months since the
last supplemental GMD
Vulnerability Assessment.
Vulnerability Assessment failed
to satisfy four of the 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 than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
31
VSL Justifications – TPL-007-2, R8
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
However, the requirement is similar to approved TPL-007-1, Requirement R4 (unchanged in proposed
TPL-007-2 Requirement R4). That requirement also has a graduated scale for VSLs.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL is worded consistently with the corresponding requirement.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
32
VSL Justifications – TPL-007-2, R8
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
33
VRF Justifications – TPL-007-2, R9
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL-007-1 Requirement R5 (unchanged in proposed TPL-007-2 Requirement R5) which requires
responsible entities to provide specific geomagnetically-induced currents (GIC) flow information to
Transmission Owners and Generator Owners for performing transformer thermal impact assessments.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the supplemental GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R9
Lower
Moderate
High
The responsible entity provided
the effective GIC time series,
GIC(t), in response to written
request, but did so more than
The responsible entity provided
the effective GIC time series,
GIC(t), in response to written
request, but did so more than
The responsible entity provided
the effective GIC time series,
GIC(t), in response to written
request, but did so more than
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
Severe
The responsible entity did not
provide the maximum effective
GIC value to the Transmission
Owner and Generator Owner
34
Proposed VSLs – TPL-007-2, R9
90 calendar days and less than
or equal to 100 calendar days
after receipt of a written
request.
100 calendar days and less than
or equal to 110 calendar days
after receipt of a written
request.
110 calendar days after receipt
of a written request.
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.
VSL Justifications – TPL-007-2, R9
NERC VSL Guidelines
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
However, the requirement is similar to approved TPL-007-1, Requirement R5 (unchanged in proposed
TPL-007-2 Requirement R5). That requirement also has a graduated scale for VSLs.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
35
VSL Justifications – TPL-007-2, R9
Uniformity and Consistency in
the Determination of Penalties
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
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
36
VRF Justifications – TPL-007-2, R10
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL-007-1 Requirement R6 (unchanged in proposed TPL-007-2 Requirement R6), which requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a supplemental transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R10
Lower
Moderate
The responsible entity failed to
conduct a supplemental thermal
impact assessment for 5% or
The responsible entity failed to
conduct a supplemental thermal
impact assessment for more
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
Severe
The responsible entity failed to
The responsible entity failed to
conduct a supplemental thermal conduct a supplemental thermal
impact assessment for more
impact assessment for more
37
Proposed VSLs – TPL-007-2, R10
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.
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;
OR
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
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;
OR
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
The responsible entity failed to
include three of the required
elements as listed in
38
Proposed VSLs – TPL-007-2, R10
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.
Requirement R10, Parts 10.1
through 10.3.
VSL Justifications – TPL-007-2, R10
NERC VSL Guidelines
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
Guideline 2a: The Single
Violation Severity Level
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
There is no prior compliance obligation related to supplemental thermal impact assessment. However,
the requirement is similar to approved TPL-007-1, Requirement R6 (unchanged in proposed TPL-007-2
Requirement R6). That requirement also has a graduated scale for VSLs.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
39
VSL Justifications – TPL-007-2, R10
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
40
VRF Justifications – TPL-007-2, R11
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD-032-1 Requirement R1 and Reliability Standard IRO-010-2 Requirement R1.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain GIC monitor data from at least one GIC monitor located in the system
would not 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.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R11
Lower
N/A
Moderate
N/A
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
N/A
Severe
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
41
Proposed VSLs – TPL-007-2, R11
Coordinator’s GIC System
Model.
VSL Justifications – TPL-007-2, R11
NERC VSL Guidelines
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
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non-compliance.
There is no prior compliance obligation for this requirement.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
42
VSL Justifications – TPL-007-2, R11
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
43
VRF Justifications – TPL-007-2, R12
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard: The requirement has no sub-requirements so a
single VRF was assigned.
Guideline 3- Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD-032-1 Requirement R1 and Reliability Standard IRO-010-2 Requirement R1.
Guideline 4- Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain geomagnetic field data for the planning area would not 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.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. This requirement
does not co-mingle a higher-risk reliability objective with a lesser- risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Proposed VSLs – TPL-007-2, R12
Lower
N/A
Moderate
N/A
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
High
N/A
Severe
The responsible entity did not
implement a process to obtain
geomagnetic field data for its
Planning Coordinator’s planning
area.
44
VSL Justifications – TPL-007-2, R12
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non-compliance.
There is no prior compliance obligation for this requirement.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL is worded consistently with the corresponding requirement.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
45
VSL Justifications – TPL-007-2, R12
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL-007-2 − Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8, 2017
46
Consideration of Directives
Reliability Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events
Order No. 830, 156 FERC ¶ 61,215 (Sep. 22, 2016)
approving Reliability Standard TPL-007-1
# P
1) PP 44
47-49
Directive/Guidance
MODIFY THE BENCHMARK GMD EVENT re SPATIAL AVERAGING
P44: “[T]he Commission, as proposed in the NOPR, directs NERC to
develop revisions to the benchmark GMD event definition so that the
reference peak geoelectric field amplitude component is not based
solely on spatially-averaged data.”
P47: “Without prejudging how NERC proposes to address the
Commission’s directive, NERC’s response to this directive should
satisfy the NOPR’s concern that reliance on spatially-averaged data
alone does not address localized peaks that could potentially affect
the reliable operation of the Bulk-Power System.”
P48: “NERC could revise [the standard] to apply a higher reference
peak geoelectric field amplitude value to assess the impact of
localized hot spots on the Bulk-Power System, as suggested by the
Trade Associations.”
Resolution
The directive is addressed in proposed TPL-007-2
through Requirements for applicable entities to perform
supplemental GMD Vulnerability Assessments based on
the supplemental GMD event. The supplemental GMD
event is a defined event for assessing system
performance that is not based on spatially-averaged
data.
The supplemental GMD event is described in the
standard drafting team's (SDT) white paper available on
the project page:
http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx
P49: “Consistent with Order No. 779, the Commission does not
specify a particular reference peak geoelectric field amplitude value
that should be applied to hot spots given present uncertainties.”
2) P65
REVISE R6 RE SPATIAL AVERAGING
P65: “Consistent with our determination above regarding the
reference peak geoelectric field amplitude value, the Commission
directs NERC to revise Requirement R6 to require registered entities
2
The directive is addressed in proposed TPL-007-2
Requirements R9 and R10. Applicable entities use
geomagnetically-induced current (GIC) information for
the supplemental GMD event to perform supplemental
thermal impact assessments of applicable power
#
P
Directive/Guidance
to apply spatially averaged and non-spatially averaged peak
geoelectric field values, or some equally efficient and effective
alternative, when conducting thermal impact assessments.”
Resolution
transformers.
Requirement R9 obligates responsible Planning
Coordinators and Transmission Planners to provide GIC
flow information to Transmission Owners and Generator
Owners for performing supplemental thermal impact
assessments. The GIC flow information is based on the
supplemental GMD event.
Requirement R10 obligates Transmission Owners and
Generator Owners to perform supplemental thermal
impact assessments on applicable power transformers
and provide results to responsible Planning Coordinators
and Transmission Planners.
3) PP 88
90,
91, 92
REVISE STANDARD TO REQUIRE COLLECTION OF GMD DATA
P 88: “The Commission … adopts the NOPR proposal in relevant part
an directs NERC to develop revisions to Reliability Standard TPL-007-1
to require responsible entities to collect GIC monitoring and
magnetometer data as necessary to enable model validation and
situational awareness, including from any devices that must be added
to meet this need.
The NERC standard drafting team should address the criteria for
collecting GIC monitoring and magnetometer data discussed below
and provide registered entities with sufficient guidance in terms of
defining the data that must be collected, and NERC should propose in
the GMD research work plan how it will determine and report on the
degree to which industry is following that guidance.”
GIC Requirements
P 91: “Each responsible entity that is a transmission owner should be
3
The directive is addressed in proposed TPL-007-2
Requirements R11 and R12.
Requirement R11 obligates responsible Planning
Coordinators and Transmission Planners to 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 SDT described GIC
data collection criteria in the guidance section to
promote consistency in achieving the reliability objective
and provide responsible entities with flexibility to tailor
procedures to their planning area. The guidance
addresses the following considerations: monitor
locations, monitor specifications, sampling interval,
collection periods, data format, and data retention.
#
P
Directive/Guidance
required to collect necessary GIC monitoring data. However, a
transmission owner should be able to apply for an exemption from
the GIC monitoring data collection requirement if it demonstrates
that little or no value would be added to planning and operations.
In developing a requirement regarding the collection of GIC
monitoring data, NERC should consider the following criteria
discussed at the March 1, 2016 Technical Conference: (1) the GIC data
is from areas found to have high GIC based on system studies; (2) the
GIC data comes from sensitive installations and key parts of the
transmission grid; and (3) the data comes from GIC monitors that are
not situated near transportation systems using direct current (e.g.,
subways or light rail.”
Magnetometer Requirements
P90: “In developing a requirement regarding the collection of
magnetometer data, NERC should consider the following criteria
discussed at the March 1, 2016 Technical Conference: (1) the data is
sampled at a cadence of at least 10-seconds or faster; (2) the data
comes from magnetometers that are physically close to GIC monitors;
(3) the data comes from magnetometers that are not near sources of
magnetic interference (e.g., roads and local distribution networks);
and (4) data is collected from magnetometers spread across wide
latitudes and longitudes and from diverse physiographic regions.”
***
P 91: GIC monitoring and magnetometer locations should also be
revisited after GIC system models are run with improved ground
conductivity models. NERC may also propose to incorporate the GIC
monitoring and magnetometer data collection requirements in a
different Reliability Standard (e.g., real-time reliability monitoring and
analysis capabilities as part of the TOP Reliability Standards).
4
Resolution
Requirement R12 obligates responsible Planning
Coordinators and Transmission Planners to implement a
process to obtain geomagnetic field data for its Planning
Coordinator’s planning area. Sources of geomagnetic
field data include government observatories, installed
equipment owned or operated by the entity, and thirdparty sources. Entities are referred to INTRAMAGNET
guidance for criteria and considerations including data
sampling rate (10-s or faster) and data format. By
requiring responsible Planning Coordinators and
Transmission Planners to obtain geomagnetic field data
for their planning areas, the requirement ensures data is
obtained from diverse geographic areas (latitudes and
longitudes) of the North American Bulk-Power System.
#
P
4) P 101,
102
Directive/Guidance
P 92: “[T]he Commission determines that requiring responsible
entities to collect necessary GIC monitoring and magnetometer data,
rather than install GIC monitors and magnetometers, affords greater
flexibility while obtaining significant benefits.”
Resolution
REVISE TPL-007 TO REQUIRE DEADLINES FOR THE DEVELOPMENT
AND COMPLETION OF CORRECTIVE ACTION PLANS
The directive is addressed in proposed TPL-007-2
Requirement R7.
P 101: “The Commission directs NERC to modify Reliability Standard
TPL-007-1 to include a deadline of one year from the completion of
the GMD Vulnerability Assessments to complete the development of
corrective action plans.”
Part 7.2 specifies that responsible entities must develop
Corrective Action Plans (CAP) within one year of
completing the benchmark GMD Vulnerability
Assessment.
P 102: “The Commission also directs NERC to modify Reliability
Standard TPL-007-1 to include a two-year deadline after the
development of the corrective action plan to complete the
implementation of non-hardware mitigation and four-year deadline
to complete hardware mitigation…”
Part 7.3 requires responsible entities to include a
timetable in the CAP that must specify:
• Implementation of non-hardware mitigation
within two years of the development of the CAP;
and
• Implementation of hardware mitigation within
four years of the development of the CAP.
Part 7.4 provides responsible entities with flexibility to
revise the CAP and timetables if situations beyond the
control of the responsible entity prevent
implementation of the CAP within the specified
timetable. The provision is necessary to account for
potential planning, siting, budgeting approval, or
regulatory uncertainties associated with transmission
system projects that are not within the responsible
entity’s control. Responsible entities are obligated to
document the revised CAP and update the revised CAP
every 12 calendar months until implemented.
5
#
P
Directive/Guidance
Resolution
Requirement R8 requires responsible entities to
complete a supplemental GMD Vulnerability
Assessment, based on the supplemental GMD event, to
evaluate localized enhancements of geomagnetic field
during a severe GMD event that could potentially affect
the reliable operation of the Bulk-Power System.
Localized enhancements of geomagnetic field can result
in geoelectric field values above the spatially-averaged
benchmark in a local area. Part 8.3 specifies that if the
responsible entity concludes that there is Cascading
caused by the supplemental GMD event, then the
responsible entity shall conduct an analysis of possible
actions to reduce the likelihood or mitigate the impacts
and the event.
Proposed TPL-007-2 does not require responsible
entities to implement a Corrective Action Plan to
address impacts identified in the supplemental GMD
Vulnerability Assessment because mandatory mitigation
on the basis of the supplemental GMD Vulnerability
Assessment may not provide effective reliability benefit
or use industry resources optimally. As discussed in the
Supplemental GMD Event Description white paper, the
supplemental GMD event is based on a small number of
observed localized enhancement events that provide
only general insight into the geographic size of localized
events during severe solar storms. Additionally, the
state-of-the-art modeling tools do not provide entities
with capabilities to realistically model localized
enhancements within a severe GMD event, and as a
result entities may need to employ conservative
approaches in the GMD Vulnerability Assessment such
as applying the localized peak geoelectric field over an
6
#
P
Directive/Guidance
Resolution
entire planning area.
The approach taken in TPL-007-2 to mitigating impacts
identified in the supplemental GMD Vulnerability
Assessment provides responsible entities with flexibility
to consider and select actions based on entity-specific
factors. This is similar to the approach taken in
Reliability Standard TPL-001-4 for extreme events (TPL001-4 Requirement R3 Part 3.5).
7
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
TPL-007-2
Reminder: Initial Ballot and Non-binding Poll Open through August 11, 2017
Now Available
An initial ballot for TPL-007-2 - Transmission System Planned Performance for Geomagnetic
Disturbance Events and non-binding poll of the associated Violation Risk Factors and Violation
Severity Levels are open through 8 p.m. Eastern, Friday, August 11, 2017.
Balloting
Members of the ballot pools associated with this project can log in and submit their vote for the
standard and non-binding poll by clicking here. If you experience any difficulties in using the Standards
Balloting and Commenting System (SBS), contact Nasheema Santos.
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 ballot results will be announced and posted on the project page. 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, Scott Barfield-McGinnis
(via email or at (404) 446-9689.
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 2013-03 Geomagnetic Disturbance Mitigation
TPL-007-2
Formal Comment Period Open through August 11, 2017
Ballot Pools Forming through July 27, 2017
Now Available
A 45-day formal comment period for TPL-007-2 - Transmission System Planned Performance for
Geomagnetic Disturbance Events, is open through 8 p.m. Eastern, Friday, August 11, 2017.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Nasheema Santos. An unofficial Word version of the comment form is
posted on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Thursday, July 27, 2017. Registered Ballot
Body members may 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
Initial ballots for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted August 2-11, 2017.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Mark Olson (via email) or at (404)
446-9760.
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 2013-03 Geomagnetic Disturbance Mitigation | June 28, 2017
2
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/95)
Ballot Name: 2013-03 Geomagnetic Disturbance Mitigation TPL-007-2 IN 1 ST
Voting Start Date: 8/2/2017 12:01:00 AM
Voting End Date: 8/11/2017 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 242
Total Ballot Pool: 303
Quorum: 79.87
Weighted Segment Value: 72.67
Negative
Fraction
w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
76
1
39
0.684
18
0.316
0
8
11
Segment:
2
7
0.4
3
0.3
1
0.1
0
0
3
Segment:
3
71
1
37
0.698
16
0.302
0
5
13
Segment:
4
16
1
7
0.636
4
0.364
0
2
3
Segment:
5
70
1
31
0.674
15
0.326
0
7
17
Segment:
6
50
1
24
0.686
11
0.314
0
4
11
Segment:
7
1
0
0
0
0
0
0
0
1
Segment:
8
3
0.2
2
0.2
0
0
0
0
1
0
0
0
0
0
Segment
Segment: 1
0.1
1
0.1
9 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
© 2018
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
10
8
0.6
6
0.6
0
0
0
1
1
Totals:
303
6.3
150
4.578
65
1.722
0
27
61
Segment
Negative
Votes w/o
Comment
Abstain
No
Vote
BALLOT POOL MEMBERS
Show
All
Segment
Search: Search
entries
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Allete - Minnesota Power,
Inc.
Jamie Monette
Abstain
N/A
1
Ameren - Ameren Services
Eric Scott
None
N/A
1
American Transmission
Company, LLC
Lauren Price
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Michelle
Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia
Robertson
Abstain
N/A
Negative
Comments
Submitted
1
Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
© 2018 - NERC Ver 4.0.3.0
Name: ERODVSBSWB01
EnergyMachine
Co.
Joe Tarantino
Segment
Designated
Proxy
Organization
Voter
1
Bonneville Power
Administration
Kammy
RogersHolliday
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
Negative
Third-Party
Comments
1
CenterPoint Energy
Houston Electric, LLC
John Brockhan
Negative
Comments
Submitted
1
Central Hudson Gas &
Electric Corp.
Frank Pace
Affirmative
N/A
1
City Utilities of Springfield,
Missouri
Michael Buyce
None
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Daniel
Grinkevich
Affirmative
N/A
1
CPS Energy
Gladys DeLaO
None
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Affirmative
N/A
1
Eversource Energy
Quintin Lee
Affirmative
N/A
1
Exelon
Chris Scanlon
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Karen Yoder
Affirmative
N/A
1
Georgia Transmission
Corporation
Jason
Snodgrass
Greg Davis
Affirmative
N/A
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Douglas Webb
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Payam
Farahbakhsh
Negative
Comments
Submitted
Negative
Comments
Submitted
1
Hydro-Qu?bec
Nicolas
TransEnergie
Turcotte
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Louis Guidry
Ballot
NERC
Memo
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
IDACORP - Idaho Power
Company
Laura Nelson
Affirmative
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
None
N/A
1
International Transmission
Company Holdings
Corporation
Michael
Moltane
None
N/A
1
KAMO Electric Cooperative
Walter Kenyon
None
N/A
1
Lakeland Electric
Larry Watt
None
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
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
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
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
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Stephanie Burns
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NiSource - Northern
Indiana Public Service Co.
Steve
Toosevich
Negative
Comments
Submitted
1
Northeast Missouri Electric
Power Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug
Peterchuck
Negative
Comments
Submitted
1
Oncor Electric Delivery
Lee Maurer
Affirmative
N/A
1
Peak Reliability
Scott Downey
Affirmative
N/A
1
Platte River Power
Authority
Matt Thompson
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Laurie Williams
Negative
Comments
Submitted
1
Portland General Electric
Co.
Scott Smith
None
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 Snohomish County
Long Duong
Abstain
N/A
1
Sacramento Municipal
Utility District
Arthur
Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Negative
Comments
Submitted
1
Santee Cooper
Shawn Abrams
Negative
Comments
Submitted
1
SCANA - South Carolina
Electric and Gas Co.
Tom Hanzlik
Affirmative
N/A
None
N/A
1
Seattle City Light
Pawel Krupa
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Eric Shaw
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
NERC
Memo
Ballot
Bret Galbraith
Negative
Comments
Submitted
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
1
Sempra - San Diego Gas
and Electric
Martine Blair
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Peter Dawson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Katherine
Prewitt
Negative
Comments
Submitted
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Negative
Third-Party
Comments
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Negative
Comments
Submitted
1
VELCO -Vermont Electric
Power Company, Inc.
Randy Buswell
None
N/A
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
sean erickson
Affirmative
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
California ISO
Richard Vine
None
N/A
2
Electric Reliability Council
of Texas, Inc.
Brandon
Gleason
None
N/A
2
ISO New England, Inc.
Michael Puscas
Negative
Comments
Submitted
2
Midcontinent ISO, Inc.
Ellen Oswald
None
N/A
2
New York Independent
System Operator
Gregory
Campoli
Affirmative
N/A
Affirmative
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
2
PJM Interconnection, L.L.C.
Mark Holman
Joshua Eason
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
Southwest Power Pool, Inc.
(RTO)
Charles Yeung
Affirmative
N/A
3
AEP
Aaron Austin
Negative
Comments
Submitted
3
AES - Indianapolis Power
and Light Co.
Bette White
None
N/A
3
Ameren - Ameren Services
David Jendras
None
N/A
3
APS - Arizona Public
Service Co.
Vivian Vo
Negative
Comments
Submitted
3
Austin Energy
W. Dwayne
Preston
Affirmative
N/A
3
Avista - Avista Corporation
Scott Kinney
None
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Affirmative
N/A
3
BC Hydro and Power
Authority
Hootan
Jarollahi
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Annette
Johnston
Darnez Gresham
Negative
Comments
Submitted
3
Black Hills Corporation
Eric Egge
Maryanne
Darling-Reich
None
N/A
3
Bonneville Power
Administration
Rebecca
Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City of Vero Beach
Ginny Beigel
Negative
Comments
Submitted
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy - Consumers
Energy Company
Karl
Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
None
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Brandon
McCormick
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Affirmative
N/A
3
Cowlitz County PUD
Russell Noble
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Affirmative
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
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
Mark Kenny
None
N/A
3
Exelon
John Bee
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
Affirmative
N/A
3
Florida Municipal Power
Agency
Joe McKinney
Negative
Comments
Submitted
3
Gainesville Regional
Utilities
Ken Simmons
Negative
Third-Party
Comments
3
Georgia System Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks, Inc.
Paul
Malozewski
Negative
Third-Party
Comments
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric System
Jason Fortik
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Brandon
McCormick
Douglas Webb
Segment
Organization
Voter
3
Manitoba Hydro
Karim AbdelHadi
3
MEAG Power
Roger Brand
3
Modesto Irrigation District
Jack Savage
3
Muscatine Power and
Water
3
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Scott Miller
Abstain
N/A
Nick Braden
Affirmative
N/A
Seth
Shoemaker
Affirmative
N/A
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.
Aimee Harris
Negative
Comments
Submitted
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
Ocala Utility Services
Randy Hahn
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald
Hargrove
Affirmative
N/A
3
Omaha Public Power
District
Aaron Smith
Negative
Comments
Submitted
3
Owensboro Municipal
Utilities
Thomas Lyons
Affirmative
N/A
3
Platte River Power
Authority
Jeff Landis
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
None
N/A
3
Portland General Electric
Co.
Angela Gaines
Abstain
N/A
3
PPL - Louisville Gas and
Electric Co.
Charles
Freibert
Affirmative
N/A
Affirmative
N/A
3
PSEG - Public Service
Jeffrey Mueller
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Electric and Gas Co.
Shelly Dineen
Segment
Organization
Voter
3
Puget Sound Energy, Inc.
Lynda Kupfer
3
Sacramento Municipal
Utility District
Nicole Looney
3
Salt River Project
3
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Affirmative
N/A
Rudy Navarro
Negative
Comments
Submitted
Santee Cooper
James Poston
Negative
Comments
Submitted
3
SCANA - South Carolina
Electric and Gas Co.
Clay Young
None
N/A
3
Seattle City Light
Tuan Tran
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Negative
Comments
Submitted
3
Sempra - San Diego Gas
and Electric
Bridget Silvia
Affirmative
N/A
3
Snohomish County PUD
No. 1
Mark Oens
Abstain
N/A
3
Southern Company Alabama Power Company
R. Scott Moore
Negative
Comments
Submitted
3
Southern Indiana Gas and
Electric Co.
Fred Frederick
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc
Donaldson
Affirmative
N/A
3
Tallahassee Electric (City of
Tallahassee, FL)
John Williams
None
N/A
3
TECO - Tampa Electric Co.
Ronald
Donahey
None
N/A
3
Tennessee Valley Authority
Ian Grant
Affirmative
N/A
3
WEC Energy Group, Inc.
Thomas
Breene
Affirmative
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
None
N/A
4
American Public Power
Jack Cashin
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Association
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Austin Energy
Esther Weekes
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Anthony Solic
Affirmative
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
Georgia System Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Keys Energy Services
Jeffrey
Partington
Brandon
McCormick
Negative
Comments
Submitted
4
North Carolina Electric
Membership Corporation
John Lemire
Scott Brame
Negative
Third-Party
Comments
4
Oklahoma Municipal Power
Authority
Ashley Stringer
None
N/A
4
Public Utility District No. 1
of Snohomish County
John Martinsen
Abstain
N/A
4
Sacramento Municipal
Utility District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Negative
Comments
Submitted
4
South Mississippi Electric
Power Association
Steve
McElhaney
None
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.
Anthony
Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
Ameren - Ameren Missouri
Sam Dwyer
None
N/A
Negative
Comments
Submitted
5
APS - Arizona Public
Kasey
Service Co.
Bohannon
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Brandon
McCormick
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Associated Electric
Cooperative, Inc.
Brad Haralson
Affirmative
N/A
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Eric
Schwarzrock
Negative
Comments
Submitted
5
Boise-Kuna Irrigation
District - Lucky Peak Power
Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
None
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Third-Party
Comments
5
City of Independence,
Power and Light
Department
Jim Nail
None
N/A
5
Cleco Corporation
Stephanie
Huffman
Affirmative
N/A
5
CMS Energy - Consumers
Energy Company
David
Greyerbiehl
Affirmative
N/A
5
Colorado Springs Utilities
Jeff Icke
None
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California Edison
Company
Thomas
Rafferty
Affirmative
N/A
Affirmative
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
5
Eversource Energy
Timothy Reyher
Jeffrey Watkins
Louis Guidry
Colby Bellville
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Exelon
Ruth Miller
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal Power
Agency
David
Schumann
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Douglas Webb
Affirmative
N/A
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Herb Schrayshuen
Herb
Schrayshuen
Affirmative
N/A
5
JEA
John Babik
None
N/A
5
Kissimmee Utility Authority
Mike Blough
Negative
Comments
Submitted
5
Lakeland Electric
Jim Howard
Affirmative
N/A
5
Lincoln Electric System
Kayleigh
Wilkerson
Affirmative
N/A
5
Lower Colorado River
Authority
Wesley Maurer
Negative
Comments
Submitted
5
Luminant - Luminant
Generation Company LLC
Alshare
Hughes
Abstain
N/A
5
Manitoba Hydro
Yuguang Xiao
Negative
Comments
Submitted
5
Massachusetts Municipal
Wholesale Electric
Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Abstain
N/A
5
Muscatine Power and
Water
Neal Nelson
None
N/A
5
National Grid USA
Elizabeth
Spivak
None
N/A
Abstain
N/A
5
NB Power Corporation
Laura McLeod
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Brandon
McCormick
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Nebraska Public Power
District
Don Schmit
Abstain
N/A
5
NiSource - Northern
Indiana Public Service Co.
Sarah
Gasienica
Negative
Comments
Submitted
5
North Carolina Electric
Membership Corporation
Robert Beadle
Negative
Third-Party
Comments
5
Northern California Power
Agency
Marty Hostler
Negative
Comments
Submitted
5
OGE Energy - Oklahoma
Gas and Electric Co.
John Rhea
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Negative
Comments
Submitted
5
Orlando Utilities
Commission
Richard Kinas
None
N/A
5
Pacific Gas and Electric
Company
Alex Chua
None
N/A
5
Portland General Electric
Co.
Ryan Olson
Abstain
N/A
5
PPL - Louisville Gas and
Electric Co.
Dan Wilson
Affirmative
N/A
5
PSEG - PSEG Fossil LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District No. 1
of Snohomish County
Sam Nietfeld
Abstain
N/A
5
Public Utility District No. 2
of Grant County,
Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy, Inc.
Eleanor Ewry
None
N/A
5
Sacramento Municipal
Utility District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
None
N/A
Negative
Comments
Submitted
5
Santee Cooper
Tommy Curtis
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Scott Brame
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
SCANA - South Carolina
Electric and Gas Co.
Alyssa Hubbard
Affirmative
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Brenda Atkins
None
N/A
5
Sempra - San Diego Gas
and Electric
Jerome Gobby
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D.
Shultz
Negative
Comments
Submitted
5
SunPower
Bradley Collard
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Chris Mattson
Affirmative
N/A
5
TECO - Tampa Electric Co.
R James
Rocha
None
N/A
5
Tennessee Valley Authority
M Lee Thomas
Affirmative
N/A
5
Tri-State G and T
Association, Inc.
Mark Stein
None
N/A
5
WEC Energy Group, Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
Laura Cox
Affirmative
N/A
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
AEP - AEP Marketing
Dan Ewing
Negative
Comments
Submitted
6
Ameren - Ameren Services
Robert
Quinlivan
None
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Basin Electric Power
Cooperative
Paul Huettl
Affirmative
N/A
Affirmative
N/A
6
Berkshire Hathaway Sandra Shaffer
PacifiCorp
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Black Hills Corporation
Eric Scherr
None
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Colorado Springs Utilities
Shannon Fair
None
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Robert Winston
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
Affirmative
N/A
6
Entergy
Julie Hall
Affirmative
N/A
6
Exelon
Becky Webb
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal Power
Agency
Richard
Montgomery
Brandon
McCormick
Negative
Comments
Submitted
6
Florida Municipal Power
Pool
Tom Reedy
Brandon
McCormick
Negative
Comments
Submitted
6
Great Plains Energy Kansas City Power and
Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna
Stephenson
Michael
Brytowski
None
N/A
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
None
N/A
6
Lower Colorado River
Authority
Michael Shaw
Abstain
N/A
Abstain
N/A
6
Luminant - Luminant
Brenda
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Energy
Hampton
Louis Guidry
Segment
Organization
Voter
6
Manitoba Hydro
Blair Mukanik
6
Modesto Irrigation District
James McFall
6
Muscatine Power and
Water
6
Designated
Proxy
Ballot
NERC
Memo
Negative
Comments
Submitted
Affirmative
N/A
Ryan Streck
Affirmative
N/A
New York Power Authority
Shivaz Chopra
Affirmative
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
None
N/A
6
NiSource - Northern
Indiana Public Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
Northern California Power
Agency
Dennis Sismaet
Negative
Comments
Submitted
6
OGE Energy - Oklahoma
Gas and Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Platte River Power
Authority
Sabrina Martz
Affirmative
N/A
6
Portland General Electric
Co.
Daniel Mason
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Affirmative
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Karla Barton
Affirmative
N/A
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
6
Salt River Project
Bobby Olsen
None
N/A
6
Santee Cooper
Michael Brown
Negative
Comments
Submitted
6
SCANA - South Carolina
Electric and Gas Co.
John Folsom
Affirmative
N/A
None
N/A
6
Seattle City Light
Charles
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Freeman
Nick Braden
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Negative
Comments
Submitted
6
Snohomish County PUD
No. 1
Franklin Lu
Abstain
N/A
6
Southern Company Southern Company
Generation and Energy
Marketing
Jennifer Sykes
Negative
Comments
Submitted
6
Southern Indiana Gas and
Electric Co.
Brad Lisembee
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie
Parsons
Affirmative
N/A
6
WEC Energy Group, Inc.
Scott Hoggatt
None
N/A
6
Westar Energy
Megan Wagner
Affirmative
N/A
7
Luminant Mining Company
LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Affirmative
N/A
8
Foundation for Resilient
Societies
William Harris
None
N/A
8
Massachusetts Attorney
General
Frederick Plett
Affirmative
N/A
9
Commonwealth of
Massachusetts Department
of Public Utilities
Donald Nelson
Affirmative
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
None
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
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Affirmative
N/A
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven
Rueckert
Affirmative
N/A
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/95)
Ballot Name: 2013-03 Geomagnetic Disturbance Mitigation TPL-007-2 IN 1 NB
Voting Start Date: 8/2/2017 12:01:00 AM
Voting End Date: 8/11/2017 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 226
Total Ballot Pool: 293
Quorum: 77.13
Weighted Segment Value: 69.19
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
71
1
32
0.696
14
0.304
15
10
Segment:
2
7
0.3
2
0.2
1
0.1
1
3
Segment:
3
69
1
28
0.683
13
0.317
13
15
Segment:
4
15
1
7
0.636
4
0.364
2
2
Segment:
5
68
1
24
0.686
11
0.314
13
20
Segment:
6
50
1
18
0.643
10
0.357
8
14
Segment:
7
1
0
0
0
0
0
0
1
Segment:
8
3
0.2
2
0.2
0
0
0
1
Segment:
9
1
0.1
1
0.1
0
0
0
0
Segment
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
10
8
0.5
5
0.5
0
0
2
1
Totals:
293
6.1
119
4.344
53
1.756
54
67
Segment
BALLOT POOL MEMBERS
Show
All
Segment
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entries
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren Services
Eric Scott
None
N/A
1
American Transmission
Company, LLC
Lauren Price
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle
Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Mark Riley
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia
Robertson
Abstain
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
Comments
Submitted
1
Bonneville Power
Administration
Affirmative
N/A
Kammy
RogersHolliday
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
Negative
Comments
Submitted
1
CenterPoint Energy
Houston Electric, LLC
John Brockhan
Abstain
N/A
1
Central Hudson Gas &
Electric Corp.
Frank Pace
Affirmative
N/A
1
City Utilities of Springfield,
Missouri
Michael Buyce
None
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Con Ed - Consolidated
Edison Co. of New York
Daniel
Grinkevich
Affirmative
N/A
1
CPS Energy
Gladys DeLaO
None
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Affirmative
N/A
1
Eversource Energy
Quintin Lee
Affirmative
N/A
1
Exelon
Chris Scanlon
Abstain
N/A
1
FirstEnergy - FirstEnergy
Corporation
Karen Yoder
Affirmative
N/A
1
Georgia Transmission
Corporation
Jason
Snodgrass
Greg Davis
Affirmative
N/A
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Douglas Webb
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Payam
Farahbakhsh
Negative
Comments
Submitted
1
Hydro-Qu?bec
TransEnergie
Nicolas
Turcotte
Negative
Comments
Submitted
1
IDACORP - Idaho Power
Company
Laura Nelson
Affirmative
N/A
None
N/A
1
Imperial Irrigation District
Jesus Sammy
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Alcaraz
Louis Guidry
Segment
Organization
Voter
1
International Transmission
Company Holdings
Corporation
Michael
Moltane
1
KAMO Electric Cooperative
1
Designated
Proxy
None
N/A
Walter Kenyon
None
N/A
Lakeland Electric
Larry Watt
None
N/A
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
Abstain
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
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
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
Negative
Comments
Submitted
1
Northeast Missouri Electric
Power Cooperative
Kevin White
Affirmative
N/A
None
N/A
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1
NorthWestern Energy
Belinda Tierney
Stephanie Burns
Ballot
NERC
Memo
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
Omaha Public Power
District
Doug
Peterchuck
Negative
Comments
Submitted
1
Peak Reliability
Scott Downey
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Laurie Williams
Affirmative
N/A
1
Portland General Electric
Co.
Scott Smith
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District No. 1
of Snohomish County
Long Duong
Abstain
N/A
1
Sacramento Municipal
Utility District
Arthur
Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Negative
Comments
Submitted
1
Santee Cooper
Shawn Abrams
Abstain
N/A
1
SCANA - South Carolina
Electric and Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
None
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Negative
Comments
Submitted
1
Sempra - San Diego Gas
and Electric
Martine Blair
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Peter Dawson
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Katherine
Prewitt
Negative
Comments
Submitted
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Joe Tarantino
Bret Galbraith
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Negative
Comments
Submitted
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Abstain
N/A
1
Tennessee Valley Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Negative
Comments
Submitted
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
sean erickson
Affirmative
N/A
2
California ISO
Richard Vine
None
N/A
2
Electric Reliability Council
of Texas, Inc.
Brandon
Gleason
None
N/A
2
ISO New England, Inc.
Michael Puscas
Negative
Comments
Submitted
2
Midcontinent ISO, Inc.
Ellen Oswald
None
N/A
2
New York Independent
System Operator
Gregory
Campoli
Abstain
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power Pool, Inc.
(RTO)
Charles Yeung
Affirmative
N/A
3
AEP
Aaron Austin
Negative
Comments
Submitted
3
AES - Indianapolis Power
and Light Co.
Bette White
None
N/A
3
APS - Arizona Public
Service Co.
Vivian Vo
Negative
Comments
Submitted
3
Austin Energy
W. Dwayne
Preston
Abstain
N/A
None
N/A
3
Avista - Avista Corporation
Scott Kinney
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Joshua Eason
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Basin Electric Power
Cooperative
Jeremy Voll
Affirmative
N/A
3
BC Hydro and Power
Authority
Hootan
Jarollahi
Abstain
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Annette
Johnston
Darnez Gresham
Negative
Comments
Submitted
3
Black Hills Corporation
Eric Egge
Maryanne
Darling-Reich
None
N/A
3
Bonneville Power
Administration
Rebecca
Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City of Vero Beach
Ginny Beigel
Negative
Comments
Submitted
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy - Consumers
Energy Company
Karl
Blaszkowski
Affirmative
N/A
3
Colorado Springs Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New York
Peter Yost
Affirmative
N/A
3
Cowlitz County PUD
Russell Noble
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
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
Mark Kenny
None
N/A
Abstain
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
3
Exelon
John Bee
Brandon
McCormick
Louis Guidry
Segment
Organization
Voter
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
3
Florida Municipal Power
Agency
Joe McKinney
3
Gainesville Regional
Utilities
3
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Negative
Comments
Submitted
Ken Simmons
Negative
Comments
Submitted
Georgia System Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks, Inc.
Paul
Malozewski
None
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric System
Jason Fortik
Abstain
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim AbdelHadi
Negative
Comments
Submitted
3
MEAG Power
Roger Brand
Scott Miller
Abstain
N/A
3
Modesto Irrigation District
Jack Savage
Nick Braden
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.
Aimee Harris
Negative
Comments
Submitted
Affirmative
N/A
3
NW Electric Power
John Stickley
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Cooperative, Inc.
Brandon
McCormick
Douglas Webb
Shelly Dineen
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Ocala Utility Services
Randy Hahn
Negative
Comments
Submitted
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald
Hargrove
Affirmative
N/A
3
Omaha Public Power
District
Aaron Smith
Negative
Comments
Submitted
3
Owensboro Municipal
Utilities
Thomas Lyons
Affirmative
N/A
3
Platte River Power
Authority
Jeff Landis
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Lynn Goldstein
None
N/A
3
Portland General Electric
Co.
Angela Gaines
Abstain
N/A
3
PPL - Louisville Gas and
Electric Co.
Charles
Freibert
None
N/A
3
PSEG - Public Service
Electric and Gas Co.
Jeffrey Mueller
Abstain
N/A
3
Puget Sound Energy, Inc.
Lynda Kupfer
None
N/A
3
Sacramento Municipal
Utility District
Nicole Looney
Affirmative
N/A
3
Salt River Project
Rudy Navarro
Negative
Comments
Submitted
3
Santee Cooper
James Poston
Abstain
N/A
3
SCANA - South Carolina
Electric and Gas Co.
Clay Young
None
N/A
3
Seattle City Light
Tuan Tran
None
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Negative
Comments
Submitted
3
Sempra - San Diego Gas
and Electric
Bridget Silvia
Affirmative
N/A
Abstain
N/A
3
Snohomish County PUD
Mark Oens
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
No. 1
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Southern Company Alabama Power Company
R. Scott Moore
Negative
Comments
Submitted
3
Tacoma Public Utilities
(Tacoma, WA)
Marc
Donaldson
Affirmative
N/A
3
Tallahassee Electric (City of
Tallahassee, FL)
John Williams
None
N/A
3
TECO - Tampa Electric Co.
Ronald
Donahey
None
N/A
3
Tennessee Valley Authority
Ian Grant
Affirmative
N/A
3
WEC Energy Group, Inc.
Thomas
Breene
Affirmative
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
American Public Power
Association
Jack Cashin
None
N/A
4
Austin Energy
Esther Weekes
Affirmative
N/A
4
FirstEnergy - FirstEnergy
Corporation
Anthony Solic
Affirmative
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
Georgia System Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Keys Energy Services
Jeffrey
Partington
Brandon
McCormick
Negative
Comments
Submitted
4
North Carolina Electric
Membership Corporation
John Lemire
Scott Brame
Negative
Comments
Submitted
4
Public Utility District No. 1
of Snohomish County
John Martinsen
Abstain
N/A
4
Sacramento Municipal
Utility District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
Negative
Comments
Submitted
4
Seminole Electric
Michael Ward
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Cooperative, Inc.
Brandon
McCormick
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
South Mississippi Electric
Power Association
Steve
McElhaney
None
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.
Anthony
Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
Ameren - Ameren Missouri
Sam Dwyer
None
N/A
5
APS - Arizona Public
Service Co.
Kasey
Bohannon
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Brad Haralson
Affirmative
N/A
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Eric
Schwarzrock
Affirmative
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak Power
Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
None
N/A
5
California Department of
Water Resources
ASM Mostafa
None
N/A
5
Choctaw Generation
Limited Partnership, LLLP
Rob Watson
Negative
Comments
Submitted
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Jeffrey Watkins
Segment
Organization
Voter
5
City of Independence,
Power and Light
Department
Jim Nail
5
Cleco Corporation
Stephanie
Huffman
5
CMS Energy - Consumers
Energy Company
5
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Affirmative
N/A
David
Greyerbiehl
Abstain
N/A
Colorado Springs Utilities
Jeff Icke
None
N/A
5
Con Ed - Consolidated
Edison Co. of New York
Dermot Smyth
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California Edison
Company
Thomas
Rafferty
Affirmative
N/A
5
Eversource Energy
Timothy Reyher
Affirmative
N/A
5
Exelon
Ruth Miller
Abstain
N/A
5
FirstEnergy - FirstEnergy
Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal Power
Agency
David
Schumann
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Douglas Webb
Affirmative
N/A
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Herb Schrayshuen
Herb
Schrayshuen
Affirmative
N/A
5
JEA
John Babik
None
N/A
5
Kissimmee Utility Authority
Mike Blough
Negative
Comments
Submitted
5
Lakeland Electric
Jim Howard
Affirmative
N/A
5
Lincoln Electric System
Kayleigh
Wilkerson
Abstain
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Louis Guidry
Colby Bellville
Brandon
McCormick
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Lower Colorado River
Authority
Wesley Maurer
Negative
Comments
Submitted
5
Luminant - Luminant
Generation Company LLC
Alshare
Hughes
None
N/A
5
Manitoba Hydro
Yuguang Xiao
Negative
Comments
Submitted
5
Massachusetts Municipal
Wholesale Electric
Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Abstain
N/A
5
Muscatine Power and
Water
Neal Nelson
None
N/A
5
National Grid USA
Elizabeth
Spivak
None
N/A
5
NB Power Corporation
Laura McLeod
Abstain
N/A
5
Nebraska Public Power
District
Don Schmit
Abstain
N/A
5
NiSource - Northern
Indiana Public Service Co.
Sarah
Gasienica
Negative
Comments
Submitted
5
Northern California Power
Agency
Marty Hostler
Negative
Comments
Submitted
5
OGE Energy - Oklahoma
Gas and Electric Co.
John Rhea
Affirmative
N/A
5
Oglethorpe Power
Corporation
Donna Johnson
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Negative
Comments
Submitted
5
Orlando Utilities
Commission
Richard Kinas
None
N/A
5
Pacific Gas and Electric
Company
Alex Chua
None
N/A
5
Portland General Electric
Co.
Ryan Olson
Abstain
N/A
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
PPL - Louisville Gas and
Electric Co.
Dan Wilson
Abstain
N/A
5
PSEG - PSEG Fossil LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1
of Snohomish County
Sam Nietfeld
Abstain
N/A
5
Public Utility District No. 2
of Grant County,
Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy, Inc.
Eleanor Ewry
None
N/A
5
Sacramento Municipal
Utility District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
None
N/A
5
Santee Cooper
Tommy Curtis
Abstain
N/A
5
SCANA - South Carolina
Electric and Gas Co.
Alyssa Hubbard
Affirmative
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Seminole Electric
Cooperative, Inc.
Brenda Atkins
None
N/A
5
Sempra - San Diego Gas
and Electric
Jerome Gobby
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D.
Shultz
Negative
Comments
Submitted
5
SunPower
Bradley Collard
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Chris Mattson
Affirmative
N/A
5
TECO - Tampa Electric Co.
R James
Rocha
None
N/A
5
Tennessee Valley Authority
M Lee Thomas
None
N/A
5
Tri-State G and T
Association, Inc.
Mark Stein
None
N/A
Abstain
N/A
5
WEC Energy Group, Inc.
Linda Horn
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Westar Energy
Laura Cox
None
N/A
6
AEP - AEP Marketing
Dan Ewing
Negative
Comments
Submitted
6
Ameren - Ameren Services
Robert
Quinlivan
None
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Basin Electric Power
Cooperative
Paul Huettl
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Black Hills Corporation
Eric Scherr
None
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Colorado Springs Utilities
Shannon Fair
None
N/A
6
Con Ed - Consolidated
Edison Co. of New York
Robert Winston
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
Affirmative
N/A
6
Entergy
Julie Hall
Affirmative
N/A
6
Exelon
Becky Webb
Abstain
N/A
6
FirstEnergy - FirstEnergy
Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal Power
Agency
Richard
Montgomery
Brandon
McCormick
Negative
Comments
Submitted
6
Florida Municipal Power
Pool
Tom Reedy
Brandon
McCormick
Negative
Comments
Submitted
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Great Plains Energy Kansas City Power and
Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna
Stephenson
Michael
Brytowski
None
N/A
6
Lakeland Electric
Paul Shipps
None
N/A
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
None
N/A
6
Lower Colorado River
Authority
Michael Shaw
Negative
Comments
Submitted
6
Luminant - Luminant
Energy
Brenda
Hampton
Abstain
N/A
6
Manitoba Hydro
Blair Mukanik
Negative
Comments
Submitted
6
Modesto Irrigation District
James McFall
Abstain
N/A
6
Muscatine Power and
Water
Ryan Streck
Affirmative
N/A
6
New York Power Authority
Shivaz Chopra
Affirmative
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
None
N/A
6
NiSource - Northern
Indiana Public Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
Northern California Power
Agency
Dennis Sismaet
Negative
Comments
Submitted
6
OGE Energy - Oklahoma
Gas and Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Platte River Power
Authority
Sabrina Martz
None
N/A
6
Portland General Electric
Co.
Daniel Mason
Abstain
N/A
None
N/A
6
PPL - Louisville Gas and
Linn Oelker
Electric Co.
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
Nick Braden
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
PSEG - PSEG Energy
Resources and Trade LLC
Karla Barton
Abstain
N/A
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
6
Salt River Project
Bobby Olsen
None
N/A
6
Santee Cooper
Michael Brown
Abstain
N/A
6
SCANA - South Carolina
Electric and Gas Co.
John Folsom
Affirmative
N/A
6
Seattle City Light
Charles
Freeman
None
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Negative
Comments
Submitted
6
Snohomish County PUD
No. 1
Franklin Lu
Abstain
N/A
6
Southern Company Southern Company
Generation and Energy
Marketing
Jennifer Sykes
Negative
Comments
Submitted
6
Southern Indiana Gas and
Electric Co.
Brad Lisembee
None
N/A
6
Tennessee Valley Authority
Marjorie
Parsons
Affirmative
N/A
6
WEC Energy Group, Inc.
Scott Hoggatt
None
N/A
6
Westar Energy
Megan Wagner
Affirmative
N/A
7
Luminant Mining Company
LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Affirmative
N/A
8
Foundation for Resilient
Societies
William Harris
None
N/A
Affirmative
N/A
8
Massachusetts Attorney
Frederick Plett
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
General
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
9
Commonwealth of
Massachusetts Department
of Public Utilities
Donald Nelson
Affirmative
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
None
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
David Greene
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven
Rueckert
Abstain
N/A
Previous
Showing 1 to 293 of 293 entries
© 2018 - NERC Ver 4.0.3.0 Machine Name: ERODVSBSWB01
1
Next
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
TPL-007-2
Formal Comment Period Open through August 11, 2017
Ballot Pools Forming through July 27, 2017
Now Available
A 45-day formal comment period for TPL-007-2 - Transmission System Planned Performance for
Geomagnetic Disturbance Events, is open through 8 p.m. Eastern, Friday, August 11, 2017.
Commenting
Use the electronic form to submit comments on the standard. If you experience any difficulties in using
the electronic form, contact Nasheema Santos. An unofficial Word version of the comment form is
posted on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Thursday, July 27, 2017. Registered Ballot
Body members may 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
Initial ballots for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted August 2-11, 2017.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Mark Olson (via email) or at (404)
446-9760.
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 2013-03 Geomagnetic Disturbance Mitigation | June 28, 2017
2
Consideration of Comments
Project Name:
Comment Period Start Date:
6/28/2017
Comment Period End Date:
8/11/2017
Associated Ballots:
2013‐03 Geomagnetic Disturbance Mitigation TPL‐007‐2 IN 1 NB
2013‐03 Geomagnetic Disturbance Mitigation TPL‐007‐2 IN 1 ST
2013‐03 Geomagnetic Disturbance Mitigation | TPL‐007‐2
There were 58 sets of responses, including comments from approximately 147 different people from approximately 106 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 Senior Director of Standards and Education, Howard Gugel
(via email) or at (404) 446‐9693.
Summary Consideration
The standard drafting team (SDT) made non‐substantive revisions to Measures M5 and M9, Rationales for Requirements R7, R11, and R12,
including a correction to a chapter reference. Additionally, the singular use of “study” in the Violation Severity Levels (VSL) for Requirement R2
was deleted because there will be at least two studies (i.e., benchmark and supplemental), and the missing word “the” was added in the
Moderate VSL for Requirement R4. For Requirement R8 in the VSLs, the text in the Lower VSL column was moved to be consistent with the
order of the text in the other three columns.
The heading for Attachment 1 was corrected to properly link as a part of the standard and not to identify it as supplemental material. Other
non‐substantive revisions addressed punctuation, formatting, and conforming the document(s) to the NERC style guide, which included
properly footnoting webpage links to reference documents.
Other supporting documents, such as, the Supplemental GMD Event white paper, Thermal Screening Criterion White Paper, and Transformer
Thermal Impact Assessment White Paper all received non‐substantive revisions addressed punctuation, formatting, and conforming the
document(s) to the NERC style guide. A few clarifying revisions were made to address comments by stakeholders.
In the Implementation Plan, the SDT clarified the phase‐in compliance dates for those Requirements that were tacitly incorporated into the
effective date language by adding additional items under the phase‐in compliance date section. Also, the SDT corrected a technical error
regarding Requirement R6. For example, if the standard happens to be approved quickly by governmental authorities, Requirement R6 could
become effective prior to the TPL‐007‐1 effective date. To correct this condition, the SDT provided a six‐month phased‐in implementation for
Requirement R6.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
2
Questions
1. The SDT developed proposed Requirements R8 – R10 and the supplemental GMD event to address FERC concerns with the benchmark
GMD event used in GMD Vulnerability Assessments. (Order No. 830 P.44, P.47‐49, P.65). The requirements will obligate responsible
entities to perform a supplemental GMD Vulnerability Assessment based on the supplemental GMD event that accounts for potential
impacts of localized peak geoelectric fields. Do you agree with the proposed requirements? If you do not agree, or if you agree but have
comments or suggestions for the proposed requirements provide your recommendation and explanation.
2. The SDT developed the Supplemental GMD Event Description white paper to provide technical justification for the supplemental
GMD event. The purpose of the supplemental GMD event description is to provide a defined event for assessing system performance for
a GMD event which includes a local enhancement of the geomagnetic field. Do you agree with the proposed supplemental GMD event
and the description in the white paper? If you do not agree, or if you agree but have comments or suggestions for the supplemental
GMD event and the description in the white paper provide your recommendation and explanation.
3. The SDT established an 85 A per phase screening criterion for determining which power transformers are required to be assessed for
thermal impacts from a supplemental GMD event in Requirement R10. Justification for this threshold is provided in the revised
Screening Criterion for Transformer Thermal Impact Assessment white paper. Do you agree with the proposed 85 A per phase screening
criterion and the technical justification for this criterion that has been added to the white paper? If you do not agree, or if you agree but
have comments or suggestions for the screening criterion and revisions to the white paper provide your recommendation and
explanation.
4. The SDT revised the Transformer Thermal Impact Assessment white paper to include the supplemental GMD event. Do you agree
with the revisions to the white paper? If you do not agree, or if you agree but have comments or suggestions on the revisions to the
white paper provide your recommendation and explanation.
5. The SDT developed proposed Requirement R7 to address FERC directives in Order No. 830 for establishing Corrective Action Plan
(CAP) deadlines associated with GMD Vulnerability Assessments (P. 101, 102). Do you agree with the proposed requirement? If you do
not agree, or if you agree but have comments or suggestions for the proposed requirement provide your recommendation and
explanation.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
3
6. The SDT developed Requirements R11 and R12 to address FERC directives in Order No. 830 for requiring responsible entities to collect
GIC monitoring and magnetometer data (P. 88; P. 90‐92). Do you agree with the proposed requirements? If you do not agree, or if you
agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
7. Do you agree with the proposed Implementation Plan for TPL‐007‐2? If you do not agree, or if you agree but have comments or
suggestions for the Implementation Plan provide your recommendation and explanation.
8. Do you agree with the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for the requirements in proposed TPL‐007‐2?
If you do not agree, or if you agree but have comments or suggestions for the VRFs and VSLs provide your recommendation and
explanation.
9. The SDT believes proposed TPL‐007‐2 provide entities with flexibility to meet the reliability objectives in the project Standards
Authorization Request (SAR) in a cost effective manner. Do you agree? If you do not agree, or if you agree but have suggestions for
improvement to enable additional cost effective approaches to meet the reliability objectives, please provide your recommendation
and, if appropriate, technical justification.
10. Provide any additional comments for the SDT to consider, if desired.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
4
Organization
Name
Brandon
McCormick
Name
Segment(s)
Brandon
McCormick
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
Region
FRCC
Group Name
FMPA
Group
Member
Name
Tim Beyrle
Group
Group
Group
Member
Member Member
Organization Segment(s) Region
City of New
4
Smyrna Beach
Utilities
Commission
FRCC
Jim Howard Lakeland
Electric
5
FRCC
Lynne Mila
City of
Clewiston
4
FRCC
Javier
Cisneros
Fort Pierce
Utilities
Authority
3
FRCC
Randy Hahn Ocala Utility
Services
3
FRCC
Don Cuevas Beaches
Energy
Services
1
FRCC
Jeffrey
Partington
Keys Energy
Services
4
FRCC
Tom Reedy Florida
Municipal
Power Pool
6
FRCC
Steven
Lancaster
3
FRCC
Beaches
Energy
Services
5
ACES Power Brian Van 6
Marketing
Gheem
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
NA ‐ Not
Applicable
Mike Blough Kissimmee
Utility
Authority
5
FRCC
Chris Adkins City of
Leesburg
3
FRCC
Ginny Beigel City of Vero
Beach
3
FRCC
3
SPP RE
ACES
Greg
Standards
Froehling
Collaborators
Rayburn
Country
Electric
Cooperative,
Inc.
Bob
Solomon
Hoosier Energy 1
Rural Electric
Cooperative,
Inc.
RF
Ginger
Mercier
Prairie Power, 1
Inc.
SERC
Shari Heino Brazos Electric 1,5
Power
Cooperative,
Inc.
Texas RE
Mark
Old Dominion 4
Ringhausen Electric
Cooperative
SERC
6
Tara Lightner Sunflower
1
Electric Power
Corporation
SPP RE
Ryan Strom Buckeye
Power, Inc.
RF
4
Scott Brame North Carolina 3,4,5
Electric
Membership
Corporation
Colby
Bellville
MRO
Colby
Bellville
Dana Klem 1,2,3,4,5,6
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
FRCC,RF,SERC Duke Energy Doug Hils
MRO
MRO NSRF
Duke Energy 1
SERC
RF
Lee Schuster Duke Energy 3
FRCC
Dale
Goodwine
Duke Energy 5
SERC
Greg Cecil
Duke Energy 6
RF
Joseph
DePoorter
Madison Gas 3,4,5,6
& Electric
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
Administration
MRO
7
Kayleigh
Wilkerson
Lincoln Electric 1,3,5,6
System
MRO
Mahmood
Safi
Omaha Public 1,3,5,6
Power District
MRO
Brad Parret Minnesota
Powert
Terry
Harbour
Elizabeth
Axson
2
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
MRO
MidAmerican 1,3
Energy
Company
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
Midcontinent 2
ISO
MRO
ERCOT
2
Texas RE
IESO
2
NPCC
PJM
2
RF
Mike
Morrow
Electric
Reliability
Council of
Texas, Inc.
1,5
IRC Standards Elizabeth
Review
Axson
Committee Ben Li
Mark
Holman
8
Lower
Colorado
River
Authority
Michael
Shaw
Manitoba
Hydro
Mike Smith 1
Southern
Company ‐
Southern
Pamela
Hunter
6
1,3,5,6
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
SERC
Greg
Campoli
NYISO
2
NPCC
Terry BIlke
Midcontinent 2
ISO, Inc.
MRO
Ali Miremadi California ISO 2
WECC
Matthew
Goldberg
ISO NE
2
NPCC
Charles
Yeung
Southwest
Power Pool,
Inc. (RTO)
2
SPP RE
LCRA
1
Texas RE
Dixie Wells
LCRA
5
Texas RE
Michael
Shaw
LCRA
6
Texas RE
Yuguang
Xiao
Manitoba
Hydro
5
MRO
Karim Abdel‐ Manitoba
Hadi
Hydro
3
MRO
Blair
Mukanik
Manitoba
Hydro
6
MRO
Mike Smith Manitoba
Hydro
1
MRO
Katherine
Prewitt
1
SERC
LCRA
Teresa
Compliance Cantwell
Manitoba
Hydro
Southern
Company
Southern
Company
Services, Inc.
9
Company
Services, Inc.
Northeast
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
Power
Coordinating
Council
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
R. Scott
Moore
Alabama
Power
Company
3
SERC
William D.
Shultz
Southern
Company
Generation
5
SERC
Jennifer G.
Sykes
Southern
Company
Generation
and Energy
Marketing
6
SERC
RSC no Hydro Guy Zito
One, HQ and
IESO
Northeast
NA ‐ Not
NPCC
Power
Applicable
Coordinating
Council
Randy
New
MacDonald Brunswick
Power
2
NPCC
Wayne
Sipperly
New York
Power
Authority
4
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian
Robinson
Utility Services 5
NPCC
10
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
Bruce
Metruck
New York
Power
Authority
6
NPCC
Alan
Adamson
New York
State
Reliability
Council
7
NPCC
Edward
Bedder
Orange &
Rockland
Utilities
1
NPCC
David Burke Orange &
Rockland
Utilities
3
NPCC
Michele
Tondalo
UI
1
NPCC
Laura
Mcleod
NB Power
1
NPCC
Michael
Forte
Con Edison
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Peter Yost
Con Edison
4
NPCC
Brian
O'Boyle
Con Edison
5
NPCC
Michael
Schiavone
National Grid 1
NPCC
11
Michael
Jones
Southwest Shannon
Power Pool, Mickens
Inc. (RTO)
2
SPP RE
SPP
Standards
Review
Group
National Grid 3
NPCC
David
Ontario Power 5
Ramkalawan Generation
Inc.
NPCC
Quintin Lee Eversource
Energy
1
NPCC
Kathleen
Goodman
ISO‐NE
2
NPCC
Greg
Campoli
NYISO
2
NPCC
Silvia
Mitchell
NextEra
6
Energy ‐
Florida Power
and Light Co.
NPCC
Sean Bodkin Dominion ‐
6
Dominion
Resources, Inc.
NPCC
Shannon
Mickens
Southwest
Power Pool
Inc.
2
SPP RE
Amy
Casuscelli
Xcel Energy
1,3,5,6
SPP RE
1,3,5,6
SPP RE
Louis Guidry Cleco
Don Schmit Nebraska
5
Public Power
District
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
SPP RE
12
Jamison
Cawley
Nebraska
1
Public Power
District
Scott Jordan Southwest
Power Pool
Santee
Cooper
Shawn
Abrams
1
Santee
Cooper
2
SPP RE
Kevin Giles
Westar Energy 1
SPP RE
Jonathan
Hayes
Southwest
Power Pool
2
SPP RE
Allan George Sunflower
1
Electric Power
Corporation
SPP RE
Tom Abrams Santee Cooper 1
SERC
Rene' Free Santee Cooper 1
SERC
Chris
Wagner
SERC
Santee Cooper 1
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
SPP RE
13
Question 1
1. The SDT developed proposed Requirements R8 – R10 and the supplemental GMD event to address FERC concerns with the benchmark
GMD event used in GMD Vulnerability Assessments. (Order No. 830 P.44, P.47‐49, P.65). The requirements will obligate responsible
entities to perform a supplemental GMD Vulnerability Assessment based on the supplemental GMD event that accounts for potential
impacts of localized peak geoelectric fields. Do you agree with the proposed requirements? If you do not agree, or if you agree but have
comments or suggestions for the proposed requirements provide your recommendation and explanation.
Thomas Foltz ‐ AEP ‐ 5
Answer
No
Document Name
Comment
AEP is concerned by the potential duplication of efforts for any assets that are brought into scope by both the Benchmark and Supplemental
Vulnerability Assessments (R6 and R10). While it may not be the drafting team’s intent that multiple thermal impact assessments be
conducted for the same assets, nor that two sets of suggested actions be developed to mitigate the impact of any GICs, the current draft does
not make this explicitly clear. AEP requests that additional clarity be added so that duplicative efforts would not be necessary for any assets
that are brought into scope under both the Benchmark and Supplemental Vulnerability Assessments. In general, the SDT should look for
opportunities to minimize the potential duplication of work and evidence requirements throughout the drafted standard.
Likes 0
Dislikes 0
Response
Thank you for your comment. It is conceivable that two separate thermal assessments may need to be done for transformers that exceed
both GIC thresholds: One for the benchmark event and one for the supplemental event. The distinction between the benchmark and
supplemental thermal assessments is that the benchmark assessment may result in a Corrective Action Plan, but the supplemental
assessment does not.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
14
Question 1
Comment
It is not clear how complying with Requirements R8 to R10 will mitigate GMD risk to BES reliability. This proposal does not address the FERC
concerns of developing a GMD benchmark not solely based on a spatially averaged magnetometer data. Manitoba Hydro (MH) believes that
specifying a one methodology in the standard is not appropriate because of the diversity of the BES across the continent and different level of
risk tolerances among the responsible entities. Instead of asking to follow a specific GMD Vulnerability Assessment methodology, MH would
like to propose the SDT to consider providing an option in the standard where the responsible entities can develop their own GMD
Assessment Methodology based on the technical knowledge obtained through the research work performed on GMD Vulnerability
Assessments in their system.
In Manitoba, for example, NRCAN has calculated the 1/100 year geoelectric field to be roughly 5 V/km at the northernmost magnetometer
site in Manitoba (Churchill) using specific model of the earth resistivity in Manitoba. NRCAN has done similar calculations for Alberta and has
also found the field to be much lower than 8 V/km as well. Rather than spatial averaging, NRCAN used extreme value mathematics to
calculate the fields.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request (SAR). The existing standard already has a
vulnerability assessment requirement that is approved and effective and subject to compliance by applicable registered entities. Any
proposed revisions to this requirement should be addressed in a new SAR.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
No
Document Name
Comment
AZPS agrees with the requirements as written, but has concerns regarding the inconsistent treatment of deadline or time‐related
requirements or sub‐requirements in the Table of Compliance Elements. More specifically, both Requirement R8 and R9 contain 90 day
deadlines for administrative activities. However, these requirements/sub‐requirements are treated differently with respect to the violation
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
15
Question 1
severity levels (VSLs). In particular, Requirement R8 treats the failure to timely provide/respond within 90 days as one element and does not
increase the VSL based on the duration of the delay beyond the 90 day time period. Conversely, Requirement R9 ties the VSL directly to the
duration of the delay beyond the 90 day time period. AZPS notes that the activities associated with the 90 day time periods are
administrative in nature, e.g., providing a report or a response, and, therefore, will have a minimal (if any) impact on the reliability of the Bulk
Electric System (BES). For this reason, AZPS recommends that the SDT conform Requirement R9 to the form provided in Requirement
R8. Such revision will provide consistency and more accurately reflect the actual or potential impact on the BES.
Likes 0
Dislikes 0
Response
Thank you for your comment. The timelines for the VSLs are consistent with the VSLs for Requirements R4 (benchmark) and R8
(supplemental) as is Requirements R5 and R9. Requirements R4 and R8 cover the days tardy as an element of the requirement and its subpart
and Requirements R5 and R9 do not.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
Document Name
Comment
Hydro‐Quebec considers that because of the specificity of its network, (on a wide area, with long transmission lines and northern location)
the benchmark event is sufficiently severe and covers the possible impact of the localized enhancement on our grid. These requirements
burden the responsible entities to perform additional assessments that are both costly and uneffective.
Based on prior real measurements done on geomagnetic local disturbances in Abitibi (see reference below), we think that it would be
preferable to wait for further analysis that takes into account real electric fields and current measures and not only magnetic measurements
and calculated electric fields. Therefore adding a supplemental event on the already severe and pessimistic benchmark event should wait.
Hydro Québec is currently in discussion with Natural Ressources Canada to complete an analysis using Canadian magnetometer data in the
province of Québec.
Hydro‐Quebec acknowledges that the requirements address the FERC concerns.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
16
Question 1
Reference: A study of geoelectromagnetic disturbances in Quebec. (IEEE Transactions on Power Delivery in 1998 and in 2000)1
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request (SAR) and FERC directives. The SDT
appreciates Hydro Québec’s research in this area and how its findings might enhance the standard in the future.
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
Hydro‐Quebec considers that because of the specificity of its network, (on a wide area, with long transmission lines and northern location)
the benchmark event is sufficiently severe and covers the possible impact of the localized enhancement on our grid. These requirements
burden the responsible entities to perform additional assessments that are both Costly and uneffective.
Based on prior real measurements done on geomagnetic local disturbances in Abitibi (see reference below), we think that it would be
preferable to wait for further analysis that takes into account real electric fields and current measures and not only magnetic measurements
and calculated electric fields. Therefore adding a supplemental event on the already severe and pessimistic benchmark event should wait.
Hydro Québec is currently in discussion with Natural Ressources Canada to complete an analysis using Canadian magnetometer data in the
province of Québec.
Hydro‐Quebec acknowledges that the requirements address the FERC concerns.
Reference: A study of geoelectromagnetic disturbances in Quebec. (IEEE Transactions on Power Delivery in 1998 and in 2000)2
Likes 0
11 http://ieeexplore.ieee.org/xpl/RecentIssue.jsp?punumber=61
2 http://ieeexplore.ieee.org/xpl/RecentIssue.jsp?punumber=61
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
17
Question 1
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request. The existing standard already has a
vulnerability assessment requirement that is approved and effective and subject to compliance by applicable registered entities. The
commenter is suggesting an alternative methodology to the existing standard which is outside the scope of the SDT and should be addressed
in a new SAR.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
No
Document Name
Comment
The intent of requirements R8 to R10 is not clear. It is understood that the intent is to address the directive in FERC Order No 830; however,
it is not clear how complying with requirements 8‐10 will mitigate GMD imposed risk to BES reliability.
Requirement R4 requires responsible entities to perform Benchmark GMD Vulnerability Assessments (based on a benchmark GMD event) to
identify risk to BES reliability. Requirement R7 requires responsible entities to mitigate the identified risk by developing a corrective action
plan.
The new requirements R8 to R10 are asking for additional assessments and evaluations to identify risk to BES reliability. The additional
assessments required in R8 is arguably repeating what is required in R4 based on an amplified GMD event called supplemental GMD
benchmark event.
It is arguable that performing the GMD vulnerability assessments based on the supplemental GMD benchmark event will result in
identification of a higher risk to BES reliability in comparison with risk identified by performing GMD assessments using the GMD benchmark
event currently in TPL‐007‐1.
Based on the current wording of the standard, the responsible entity is not required to consider the elevated risk (based on the supplemental
GMD assessments) in their corrective action plans. Requirement 8.3 states:
“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.”
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
18
Question 1
The word “evaluation” suggests further assessments but not necessarily any further mitigations of risk. So the real question is why would
responsible entities be required to perform a supplemental assessment? And how is this additional assessment designed to mitigate risk to
BES reliability?
The Standard Drafting Team has not revised the GMD benchmark event definition rather they introduced a new supplemental GMD event to
account for potential impacts of localized peak geoelectric filed.
In paragraph 44, FERC Order No. 830 directed NERC to revise the GMD benchmark event definition so that the reference peak geoelectric
field amplitude component is not solely based on spatially‐averaged data. This approach will burden the responsible entities to perform
additional assessments without a clear outcome.
We recommend that the Standard Drafting Team follow the results based standard development concept. The requirements should be
focused on required actions or results (the "what") and not necessarily the methods by which to accomplish those actions or results (the
"how").
Paragraph 65 in FERC Order No. 830 suggests that NERC could propose “some equally efficient and effective alternative”. An alternative
approach is to move away from specifying a methodology as the only option to perform GMD assessments in the standard. Instead, create an
option for the entities to develop their own GMD assessment methodology based on their own research of GMD risks to and impact on BES
reliability.
Responsible entities across the continent have diverse systems, equipment, resources, and risk tolerance. Specifying a one approach fits‐all
does not seem to be appropriate.
The benchmark GMD event and the supplemental GMD event described in the whitepapers (and currently referenced within the standard
requirements) can each be used to perform GMD assessments; however, the standard should not limit the entities to only use these
prescribed GMD events. Instead, the standard should allow entities to perform GMD assessments based on alternative GMD events as
justified by the responsible entities based on their own research and methodology.
Ultimately, whichever GMD assessment methodology the responsible entity chooses to use, the system‐wide impact and transformer thermal
impact should be assessed.
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
19
Question 1
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request and FERC directives. The existing standard
already has a vulnerability assessment requirement that is approved, and effective and subject to compliance by applicable registered
entities. The supplemental assessment has been added to address local enhancements, but without the requirement of a Corrective Action
Plan. Any proposed revisions to this requirement should be addressed in a new SAR. The Transformer Thermal Impact Assessment White
Paper and Screening Criterion for Transformer Thermal Impact Assessment documents have provided the technical foundation and
methodologies that can be used to conduct transformer temperature rise calculations for both the benchmark case and the supplemental
case.
Joel Robles ‐ Omaha Public Power District ‐ 1,3,5,6
Answer
No
Document Name
Comment
. OPPD will be supporting MRO NSRF comments. Please note this on your ballot when you vote.
Likes 0
Dislikes 0
Response
Thank you for supporting the MRO NSRF comments.
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
No
Document Name
Comment
OPG agrees that proposed Requirements R8 – R10 and the supplemental GMD event attempts to address FERC concerns with the benchmark
GMD event used in GMD Vulnerability Assessments, however they fell short of mitigating GMD risk to the reliability of BES.
Requirement R10 – “10.3. Describe suggested actions and supporting analysis to mitigate the impact of GICs, if any; ..” is just a good intention
and cannot account for a Corrective Action Plan.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
20
Question 1
Moreover we now have two type of GMD events the Benchmark and the Supplemental; OPG is of the opinion that they should be
amalgamated in one GMD type of events (albeit this may require GMD benchmark event definition revision). OPG believes that Supplemental
GMD event assessment will render the Benchmark GMD event assessment obsolete (based on the more stringent condition) and thus will be
an unnecessary budgetary burden.
Only Requirement R4 based on the benchmark GMD event VA is leading to a CAP via R7, and this does not happen for the Supplemental GMD
event VA based on the new R8 – R10
Likes 0
Dislikes 0
Response
The SDT is being responsive to the Standards Authorization Request. The existing standard already has a vulnerability assessment
requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental assessment has
been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is suggesting an
alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR. The
Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal Impact Assessment documents have
provided the technical foundation and methodologies that can be used to conduct transformer temperature rise calculations for both the
benchmark case and the supplemental case.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
NCPA disagrees with having to perform supplemental GMD assessments. If it is to be required, then there should be a TRF MVA threshold of
500 MVA or greater. NCPA also disagrees with having to provide any assessment to any registered entity, other than our TP or RC.
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
21
Question 1
The SDT is being responsive to the Standards Authorization Request and FERC directives. The existing standard already has a vulnerability
assessment requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental
assessment has been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is
suggesting an alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a
new SAR. The Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal Impact Assessment
documents have provided the technical foundation and methodologies that can be used to conduct transformer temperature rise calculations
for both the benchmark case and the supplemental case. Providing the assessment to others has a reliability benefit.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
NCPA disagrees with having to perform supplemental GMD assessments. If it is to be required, then there should be a TRF MVA threshold of
500 MVA or greater. NCPA also disagrees with having to provide any assessment to any registered entity, other than our TP or RC.
Likes 0
Dislikes 0
Response
The SDT is being responsive to the Standards Authorization Request. The existing standard already has a vulnerability assessment
requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental assessment has
been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is suggesting an
alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR. The
Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal Impact Assessment documents have
provided the technical foundation and methodologies that can be used to conduct transformer temperature rise calculations for both the
benchmark case and the supplemental case.
Since GMD events are likely to be wide‐area, it is necessary to share the information with other entities.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
22
Question 1
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
No
Document Name
Foundation for Resilient Societies on NERC Project 2013 081117_Submitted.docx
Comment
Resilient Societies has concerns that the relevant classes of GMD events are not fully addressed; that the 75 amps per phase threshhold is
imprudent and not science based, and that a complementary effort is needed to test equipment under load and to test long replacement
time equipment types to destruction. See attacheed Comments.
Likes 0
Dislikes 0
Response
Thank you for your comment. Please see the responses at the end of this document referencing the attached comments.
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
This will place considerably more of a burden on the entities performing the GMD Vulnerability Assessments with the need to perform
another whole assessment, but also, presumably, with the need to collect the data needed for creation of a "localized peak geoelectric field".
Likes 0
Dislikes 0
Response
Thank you for your comment. The supplemental assessment is additional work, but it is necessary to account for the impacts of local
enhancements. No additional system data are required.
Joe O'Brien ‐ NiSource ‐ Northern Indiana Public Service Co. ‐ 6
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
23
Question 1
Answer
Yes
Document Name
Comment
NIPSCO agrees that supplemental GMD vulnerability assessment accounts for potential impact of localized peak geo‐electric fields. However,
instead of its own set of requirements, we feel it is appropriate to consider the supplemental GMD vulnerability assessment as a sensitivity
case to the benchmark GMD vulnerability assessment. In addition, Requirement R8 requires conducting analysis for any potential cascading
due to supplemental GMD event. However, R4 (Benchmark GMD vulnerability assessment) does not require such potential cascading
evaluation. A uniformity in requirement would be desirable.
Likes 0
Dislikes 0
Response
Thank you for your comment. Requirement R8 focuses on Cascading because the supplemental event is a more extreme event than the
benchmark event.
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
The supplemental GMD vulnerability assessment does not appear to be an overly onerous burden on the responsible entities as it is an
enhancement based on the already required benchmark assessment. The potential impacts of localized peaks are necessary to evaluate due
to the short time constant of the windings and structures affected by stray fields resulting from part cycle saturation.
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
24
Question 1
Thank you for your comment. The SDT agrees that the impacts of local enhancements need to be considered in network analysis and
transformer assessment.
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
For R8.4 and R9 and their associated measures, BPA proposes rather than “shall be provided/shall provide” that the wording be changed to
“shall make available.” For the western interconnection, a separate entity may be collecting interconnection‐wide data.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT does not agree with revising the language as it would affect the responsibilities as proposed in the
standard.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
Yes
Document Name
Comment
The ability to perform a system‐wide study at the supplemental GMD level is helpful in cases where software cannot support a localized
event. It is not overly clear why 85 A is acceptable for the supplemental assessment vs. 75 A for the benchmark assessment. The distinction
between the two should be made clearer (e.g. “85 A is acceptable even as a higher value because the local (higher magnitude) field is
assumed to be applied for a shorter duration”)
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
25
Question 1
Response
Thank you for your comment. From a hot spot temperature rise point of view, 75 A/phase and 85 A/phase are equivalent. A more detailed
explanation has been added to the Screening Criterion for Transformer Thermal Impact Assessment white paper above Table 2.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
TPLTF3 Discussion: The group agrees with the SDT approach to addressing FERC Order No. 830 Paragraph 44. In effect, the SDT has specified
an extreme value for geoelectric field, called the supplemental GMD event, intended to represent a locally‐enhanced geoelectric field
experienced by a limited geographic area. In other words, the SDT has proposed a means by which Planning Coordinators and Transmission
Planners can approximate a non‐geospatially‐averaged peak geoelectric field, thus meeting the intent of the FERC Order No. 830
directive. While determining peak geoelectric field amplitudes not based solely on spatially‐averaged data is a significant challenge to
meeting the FERC directive, primarily because of the lack of North American data, as well as analytical tools available to Planning Coordinators
and Transmission Planners, the group believes the SDT has found a workable approach.
The group would like to note that it will be non‐trivial to apply the localized peak geoelectric field in the supplemental GMD event to a
spatially‐limited area, described in the proposed TPL‐007‐2 Attachment 1, given available software tools and available personnel
resources. This will be especially pronounced for Planning Coordinators and Transmission Planners with large geographical footprints. Many
planning entities will be forced to apply the supplemental peak geoelectric field over their entire area, in effect simply studying a higher
magnitude benchmark GMD event. While the group believes this is prominently conservative, as stated above, we understand and support
the SDT approach to this directive. It is likewise noted that the definition of a spatially‐limited area is absent in the materials published by the
SDT, but this vagary supports better analytical flexibility for Planning Coordinators and Transmission Planners and should not be defined in
the draft standard.
Likes 0
3 TPLTF document is found at the end of this document in Attachment 1.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
26
Question 1
Dislikes 0
Response
Thank you for your comment. The comment is an excellent summary of the intent of the SDT relative to accountinkg for the impacts of local
enhancements. The SDT provides considerable flexibility to the planners as to how to reflect the supplemental event into their assessments.
The SDT believes that this is especially appropriate for the planners who are dealing with very large systems.
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
SRP supports the response provided by WAPA on behalf of TPLTF4 for question 1
Likes 0
Dislikes 0
Response
Thank you for your comment. The comment is an excellent summary of the intent of the SDT relative to accounting for the impacts of local
enhancements. The SDT provides considerable flexibility to the planners as to how to reflect the supplemental event into their assessments.
The SDT believes that this is especially appropriate for the planners who are dealing with very large systems.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
Yes
Document Name
Comment
4 TPLTF document is found at the end of this document in Attachment 1.
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
27
Question 1
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) commends the efforts of the SDT and believes Requirements R8 – R10
address FERC concerns with the benchmark GMD event used in GMD Vulnerability Assessments. Additionally, CenterPoint Energy agrees that
the supplemental GMD Vulnerability Assessment accounts for potential impact of localized peak geo‐electric fields”.
CenterPoint Energy shares AEP’s concern with the potential duplication of efforts for any assets that are brought into scope by both the
Benchmark and Supplemental Vulnerability Assessments (R6 and R10). While it may not be the drafting team’s intent that multiple thermal
impact assessments be conducted for the same assets, nor that two sets of suggested actions be developed to mitigate the impact of any
GICs, the current draft does not make this explicitly clear. CenterPoint Energy supports AEP’s request that additional clarity be added so that
duplicative efforts would not be necessary for any assets that are brought into scope under both the Benchmark and Supplemental
Vulnerability Assessments.
Likes 0
Dislikes 0
Response
The SDT is being responsive to the Standards Authorization Request. The existing standard already has a vulnerability assessment
requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental assessment has
been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is suggesting an
alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR. The
Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal Impact Assessment documents have
provided the technical foundation and methodologies that can be used to conduct transformer temperature rise calculations for both the
benchmark case and the supplemental case.
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
While disagreeing with the original FERC determination requiring the modification to the benchmark GMD event so that the assessments are
not based solely on spatially‐averaged data using the determined reference 8 V/km peak geoelectric field amplitude, we do agree on the
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
28
Question 1
SDT’s proposal of conducting a supplemental assessment using 12 V/km as the reference non‐spatially averaged peak geoelectric field
amplitude (as opposed to using the alternative 20 V/km non‐spatially averaged peak value noted by FERC in the GMD Interim Report which
would have overestimated the severity of a 1‐in‐100 year GMD event ).
Likes 0
Dislikes 0
Response
Thank you for your comment.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group agrees with the SDT approach to addressing FERC Order No. 830 Paragraph 44. In effect, the SDT has
specified an extreme value for geoelectric field, called the supplemental GMD event, intended to represent a locally‐enhanced geoelectric
field experienced by a limited geographic area. In other words, the SDT has proposed a means by which Planning Coordinators and
Transmission Planners can approximate a non‐geospatially‐averaged peak geoelectric field, thus meeting the intent of the FERC Order No. 830
directive. While determining peak geoelectric field amplitudes not based solely on spatially‐averaged data is a significant challenge to
meeting the FERC directive, primarily because of the lack of North American data, as well as analytical tools available to Planning Coordinators
and Transmission Planners, the group believes the SDT has found a workable approach.
The group would like to note that it will be non‐trivial to apply the localized peak geoelectric field in the supplemental GMD event to a
spatially‐limited area, described in the proposed TPL‐007‐2
Attachment 1, given available software tools and available personnel resources. This will be especially pronounced for Planning Coordinators
and Transmission Planners with large geographical footprints. Many planning entities will be forced to apply the supplemental peak
geoelectric field over their entire area, in effect simply studying a higher magnitude benchmark GMD event. While the group believes this is
prominently conservative, as stated above, we understand and support the SDT approach to this directive. It is likewise noted that the
definition of a spatially‐limited area is absent in the materials published by the SDT, but this vagary supports better analytical flexibility for
Planning Coordinators and Transmission Planners and should not be defined in the draft standard.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
29
Question 1
Likes 0
Dislikes 0
Response
Thank you for your comment. The comment is an excellent summary of the intent of the SDT relative to accounting for the impacts of local
enhancements. The SDT provides considerable flexibility to the planners as to how to reflect the supplemental event into their assessments.
The SDT believes that this is especially appropriate for the planners who are dealing with very large systems.
Chris Scanlon ‐ Exelon ‐ 1
Answer
Yes
Document Name
Comment
See comment to Q 3.
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
30
Question 1
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
31
Question 1
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
32
Question 1
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
33
Question 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
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
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
34
Question 1
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
35
Question 1
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
36
Question 1
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
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
37
Question 1
Dislikes 0
Response
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
38
Question 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
39
Question 1
Likes 0
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
40
Question 1
Sarah Gasienica ‐ NiSource ‐ Northern Indiana Public Service Co. ‐ 5
Answer
Document Name
Comment
Please see comments of Joesph N. O'Brien.
Likes 0
Dislikes 0
Response
Romel Aquino ‐ Edison International ‐ Southern California Edison Company ‐ 3
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison.
Likes 0
Dislikes 0
Response
No comments were submitted.
Kenya Streeter ‐ Edison International ‐ Southern California Edison Company ‐ 6
Answer
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
41
Question 1
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison.
Likes 0
Dislikes 0
Response
No comments were submitted.
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
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
42
Question 1
No comments were submitted.
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
43
Question 2
2. The SDT developed the Supplemental GMD Event Description white paper to provide technical justification for the supplemental GMD
event. The purpose of the supplemental GMD event description is to provide a defined event for assessing system performance for a GMD
event which includes a local enhancement of the geomagnetic field. Do you agree with the proposed supplemental GMD event and the
description in the white paper? If you do not agree, or if you agree but have comments or suggestions for the supplemental GMD event
and the description in the white paper provide your recommendation and explanation.
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
No
Document Name
Comment
This is duplicative, but worse, both threshholds are likely to be above actual thresholds at which transformers catch fire, epxlode, or both.
Likes 0
Dislikes 0
Response
Thank you for your comment. Different screening thresholds were selected because benchmark and supplemental benchmark waveforms are
different and their effects on healthy transformers are different for the same peak current. The temperature thresholds are consistent, i.e.,
the thermal effects on a transformer are characterized by peak temperatures.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits.
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
44
Question 2
Dislikes 0
Response
Thank you for your comment. In the development of the TPL‐007‐2: Transmission System Planned Performance for Geomagnetic Disturbance
Events standard with supplemental GMD event, the SDT is being responsive to the Standards Authorization Request. The consensus of the
SDT is that the supplemental GMD Vulnerability Assessment provides a reliability benefit.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits.
Likes 0
Dislikes 0
Response
Thank you for your comment. The Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal
Impact Assessment documents have provided the technical foundation and methodologies that can be used to conduct transformer
temperature rise calculations for both the benchmark case and the supplemental case.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC, Group Name Southern Company
Answer
No
Document Name
Comment
1. Paragraph 2, page 12 of the Supplemental GMD Event Description White Paper – the Drafting Team briefly discusses that the
geographic area of the local enhancement is on the order of 100 km in N‐S (latitude) and on the order of 500 km E‐W (longitude). We
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
45
Question 2
recommend the SDT to provide additional information on the selection of ‘on the order of 500 km’ for longitudinal width. It is not
clear why and how a width of 500 km(s) was selected. Why not consider a longitudinal width on the order of 100 km?
2. Figure II‐1, page 17 – we recommend the Drafting Team to include a legend that clearly shows what each line means. This figure shows
numerous lines (e.g., vertical, horizontal, etc.) that can lead to confusion.
3. Equation II.3, page 18, is missing the equal ‘=’ sign (Epeak = ...)
Likes 0
Dislikes 0
Response
Thank you for your comment.
1. The geographic dimensions of local enhancements are based on a very limited set of events; therefore, flexibility is provided in the
requirements in how to apply the dimensions in the analysis. A minor change was made in the reference to Figure II‐1 in the
Supplemental GMD Event Description document.
2. Correction made to the Supplemental GMD Event Description document.
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
No
Document Name
Comment
While ISO‐NE supports the supplemental event, it believes that the probability of the event occurring in the lower 48 state portion of the
United States is far less than once in one hundred years. The magnitude of enhancement is based on measurements from the IMAGE
magnetometer stations which are located in northern Europe, rather than observations in the United States. Also, the four examples in the
Supplemental Geomagnetic Event Description in Figures I‐4,5,6 &7 all occur in far northern latitudes and it is not clear that these events will
occur in more southern latitudes.
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
46
Question 2
Thank you for your comment. The IMAGE dataset is the most complete and comprehensive data available and is therefore the best data
source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there
is no evidence that the local enhancement effect only occurs in high latitudes.
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
see comments to Question 1.
Likes 0
Dislikes 0
Response
Thank you for your comment. See response in Question 1.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
Document Name
Comment
See comments to Question 1.
Likes 0
Dislikes 0
Response
Thank you for your comment. See response in Question 1.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
47
Question 2
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
We think that we are still at the infancy of understanding the nature and mechanism of these local enhancements. The Geophysics need more
time to study this phenomenon and figure out how to simulate it in our GIC Simulator.
Are the current state of the art assessment tools capable of modeling a “local” enhancement? Given the tools limitations, Transmission
Planners will likely model the supplemental GMD event as a uniform field over the entire assessment area. It is not clear whether this is
acceptable or whether this stress transformers in a similar way as a non‐uniform field analysis.
Likes 0
Dislikes 0
Response
Thank you for your comment. The TPL‐007‐2 does not restrict the technically justified methodology for the industry to perform the local
enhancement GMD event assessment due to the evolving understanding of local enhancements.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
No
Document Name
Comment
TPLTF5 Discussion: The group recognizes that there are multiple methods to approach revisions to the benchmark GMD event definition so
that the reference peak geoelectric field amplitude component is not based solely on spatially‐averaged data (FERC Order No. 830 Paragraph
44). However, given a wide diversity in available data, analytical tools, and personnel expertise, the group believes that the SDT has found a
5 TPLTF document is found at the end of this document in Attachment 1.
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48
Question 2
practical approach to meeting the objective of the FERC directive. Moreover, the Supplemental GMD Event Description white paper presents
a reasoned justification for the use of the geoelectric field amplitude of 12 V/km.
The group recommends that the SDT consider a less ambiguous name for the Supplemental GMD Event; the group believes Extreme Value
GMD Event would be more appropriate for the following reasons:
{C}a. {C}Implies a closer relationship to the extreme events of TPL‐001‐4 for which Planning Coordinators and Transmission Planners are
familiar.
{C}b. {C}Is better aligned with the extreme value statistical analysis that was conducted to produce the subject reference peak geoelectric
field amplitude.
{C}c. {C}Indicates a measure of how rare the extreme value for the 1‐in‐100 year peak geoelectric field amplitude may be, based upon the
95% confidence interval of the extreme value.
While the group agrees that the application of extreme value statistical methods presented in the Supplemental GMD Event Description white
paper is sound, three clarifying statements should be made in the white paper. Firstly, in short, the group agrees that by using the 23 years of
daily maximum geoelectric field amplitudes from IMAGE magnetometers, a proxy of higher magnitude events can be characterized. It is
noted that the southernmost magnetometer in the IMAGE chain resides in Suwałki, Poland at 54.01°N, whose geographic latitude places it
roughly 500 miles north of Quebec. Given that geoelectric field is highly correlated with geomagnetic latitude rather than geographic
latitude, the IMAGE data should still be referred to as a loose approximation for estimated North American geoelectric field magnitudes
(Suwałki, Poland geomagnetic dipole latitude 52°N, Quebec geomagnetic dipole latitude 56°N). In other words, the group believes it is
appropriate to qualify that the extreme value analysis performed in the white paper is based upon maximum data points obtained from an
array of northern geomagnetically‐biased latitudes, further inflated by using the high earth conductivity of Quebec. Secondly, it is well known
that coastal geological conditions can lead to locally‐enhanced geoelectric fields, not observed in regions more distant from the coast. Given
that nearly all of the IMAGE chain magnetometers reside within 100 miles of the northern Atlantic Ocean or Baltic Sea coasts, it is reasonable
to conclude that the geoelectric field amplitudes derived from the corresponding IMAGE data may have suffered from geoelectric field
enhancement along conductivity boundaries. With respect to serving as a proxy for mainland North American peak geoelectric field
amplitude, the SDT should consider further qualifying the appropriateness of the IMAGE data which served as the foundation of the extreme
value analysis. Finally, the group agrees that the use of more resolute point over threshold (POT) methods was indicated over generalized
extreme value (GEV). For clarity, however, it should be emphasized that the geoelectric field amplitude of 12 V/km represents the extreme
value of the upper limit of the 95 percent confidence interval for a 100‐year return interval. In other words, the statistical significance of the
extreme value confidence interval is not equivalent to the statistic expressed by the confidence interval for the data set consisting of 23 years
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
49
Question 2
of all sampled geoelectric field amplitudes (not shown). Each of these considerations, if addressed, can strengthen the conclusions of the
white paper by emphasizing its conservative approach.
Likes 0
Dislikes 0
Response
Thank you for supporting the SPP TPLTF comments6 on the TPL‐007‐2 standard. The IMAGE dataset is the most complete and comprehensive
data available and is therefore the best data source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there
is no evidence that the local enhancement effect only occurs in high latitudes. Based on the past experiences with the IMAGE data, it is not
expected that the coastal effect has a significant effect on the geomagnetic fields that were used in the extreme value analysis.
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
While IRC supports the supplemental event description, it believes that the probability of this event occurring in the lower 48 state portion of
the United States is far less than once in one hundred years. The magnitude of enhancement is based on measurements from the IMAGE
magnetometer stations which are located in northern Europe, rather than observations in the United States. Also, the four examples in the
Supplemental Geomagnetic Event Description in Figures I‐4, 5, 6 & 7 all occur in far northern latitudes and it is not clear that these events will
occur in more southern latitudes.
Likes 0
Dislikes 0
6 TPLTF document is found at the end of this document in Attachment 1.
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
50
Question 2
Response
Thank you for your comment. The IMAGE dataset is the most complete and comprehensive data available and is therefore the best data
source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there
is no evidence that the local enhancement effect only occurs in high latitudes.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group recognizes that there are multiple methods to approach revisions to the benchmark GMD event definition
so that the reference peak geoelectric field amplitude component is not based solely on spatially‐averaged data (FERC Order No. 830
Paragraph 44). However, given a wide diversity in available data, analytical tools, and personnel expertise, the group believes that the SDT
has found a practical approach to meeting the objective of the FERC directive. Moreover, the Supplemental GMD Event Description white
paper presents a reasoned justification for the use of the geoelectric field amplitude of 12 V/km.
We recommend that the SDT consider a less ambiguous name for the Supplemental GMD Event; the group believes Extreme Value GMD
Event would be more appropriate for the following reasons:
1. Implies a closer relationship to the extreme events of TPL‐001‐4 for which Planning Coordinators and Transmission Planners are
familiar.
2. Is better aligned with the extreme value statistical analysis that was conducted to produce the subject reference peak geoelectric field
amplitude.
3. Indicates a measure of how rare the extreme value for the 1‐in‐100 year peak geoelectric field amplitude may be, based upon the 95%
confidence interval of the extreme value.
While we agree that the application of extreme value statistical methods presented in the Supplemental GMD Event Description white paper
is sound, three clarifying statements should be made in the white paper. Firstly, in short, the group agrees that by using the 23 years of daily
maximum geoelectric field amplitudes from IMAGE magnetometers, a proxy of higher magnitude events can be characterized. It is noted that
the southernmost magnetometer in the IMAGE chain resides in Suwałki, Poland at 54.01°N, whose geographic latitude places it roughly 500
miles north of Quebec. Given that geoelectric field is highly correlated with geomagnetic latitude rather than geographic latitude, the IMAGE
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Question 2
data should still be referred to as a loose approximation for estimated North American geoelectric field magnitudes (Suwałki, Poland
geomagnetic dipole latitude 52°N, Quebec geomagnetic dipole latitude 56°N). In other words, the group believes it is appropriate to qualify
that the extreme value analysis performed in the white paper is based upon maximum data points obtained from an array of northern
geomagnetically‐biased latitudes, further inflated by using the high earth conductivity of Quebec. Secondly, it is well known that coastal
geological conditions can lead to locally‐enhanced geoelectric fields, not observed in regions more distant from the coast. Given that nearly
all of the IMAGE chain magnetometers reside within 100 miles of the northern Atlantic Ocean or Baltic Sea coasts, it is reasonable to conclude
that the geoelectric field amplitudes derived from the corresponding IMAGE data may have suffered from geoelectric field enhancement
along conductivity boundaries. With respect to serving as a proxy for mainland North American peak geoelectric field amplitude, the SDT
should consider further qualifying the appropriateness of the IMAGE data which served as the foundation of the extreme value
analysis. Finally, the group agrees that the use of more resolute point over threshold (POT) methods was indicated over generalized extreme
value (GEV). For clarity, however, it should be emphasized that the geoelectric field amplitude of 12 V/km represents the extreme value of
the upper limit of the 95 percent confidence interval for a 100‐year return interval. In other words, the statistical significance of the extreme
value confidence interval is not equivalent to the statistic expressed by the confidence interval for the data set consisting of 23 years of all
sampled geoelectric field amplitudes (not shown). Each of these considerations, if addressed, can strengthen the conclusions of the white
paper by emphasizing its conservative approach.
Likes 0
Dislikes 0
Response
Thank you for supporting the SPP TPLTF comments7 on the TPL‐007‐2 standard. The IMAGE dataset is the most complete and comprehensive
data available and is therefore the best data source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there
is no evidence that the local enhancement effect only occurs in high latitudes. Based on the past experiences with the IMAGE data, it is not
expected that the coastal effect has a significant effect on the geomagnetic fields that were used in the extreme value analysis.
7 TPLTF document is found at the end of this document in Attachment 1.
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Question 2
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
The supplemental GMD event definition was determined through statistical analysis of available geomagnetic field data and corresponding
calculations. The same data set and similar techniques were used in defining the benchmark GMD event with the exception that the
supplemental definition was based on observations at each individual station vs. spatially averaging.
Likes 0
Dislikes 0
Response
Thank you for your comment. The IMAGE array data does represent high geomagnetic latitude observations and this is why (alpha) scaling of
the determined geoelectric field amplitudes is necessary for carrying out analyses at lower latitude locations. Based on the past experiences
with the IMAGE data, it is not expected that the coast effect has a significant effect on geomagnetic fields that were used in the extreme
value analysis.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
Yes
Document Name
Comment
CenterPoint Energy agrees with the proposed supplemental GMD event and the description in the white paper. CenterPoint Energy believes
the conservative approach is appropriate and reasonable and is the result of successful collaboration between GMD research experts, the
space agency experts, and modeling experts from the power industry.
Likes 0
Dislikes 0
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Question 2
Response
Thank you for your comment.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
Yes
Document Name
Comment
Applying a higher magnitude, localized event would seem to be prudent for assessing that type of phenomenon per FERC’s request.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Thomas Foltz ‐ AEP ‐ 5
Answer
Yes
Document Name
Comment
AEP agrees with the methodology behind the Supplemental GMD Event Description, but has concerns with how the standard has been revised
to perform two separate assessments.
Likes 0
Dislikes 0
Response
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Question 2
Thank you for your comment. The SDT purposely is requesting two separate thermal assessments be done for transformers that exceed the
GIC thresholds: One for the benchmark event and one for the supplemental event. The supplemental assessment is intended to address local
enhancements. The benchmark assessment may result in a Corrective Action Plan, but the supplemental assessment does not.
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Chris Scanlon ‐ Exelon ‐ 1
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Question 2
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 2
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 2
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
Yes
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
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Question 2
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
59
Question 2
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
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
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
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Question 2
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
61
Question 2
Likes 0
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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62
Question 2
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
63
Question 2
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 2
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
65
Question 2
Comment
Likes 0
Dislikes 0
Response
Joe O'Brien ‐ NiSource ‐ Northern Indiana Public Service Co. ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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66
Question 2
Response
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
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Question 2
Document Name
Comment
While OPG agrees with the technical content of the Supplemental GMD Event Description white paper the SDT approach ends up with two
type of GMD events the Benchmark and the Supplemental; OPG is of the opinion that they should be amalgamated in one GMD type of
events (albeit this may require GMD benchmark event definition revision). As stated in question #1 OPG believes that Supplemental GMD
event assessment will render the Benchmark GMD event assessment obsolete (based on the more stringent condition) and thus will be an
unnecessary budgetary burden.
Likes 0
Dislikes 0
Response
The SDT is being responsive to the Standards Authorization Request. The existing standard already has a vulnerability assessment
requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental assessment has
been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is suggesting an
alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
Document Name
Comment
We do not agree or disagree with the white paper. We believe that our industry’s experience with GMD is not mature enough to adopt one
specific approach to GMD assessment. The existing and recently developed assessment methodologies can be eventually verified by allowing
the industry to collect GMD monitoring data and do further research.
Again, we disagree with the standard specifying methodologies for the responsible entities. We believe that this approach should be an
option (in the guidelines or documented as an implementation guidance) but not the only option.
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
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Question 2
Dislikes 0
Response
The SDT is being responsive to the Standards Authorization Request. The existing standard already has a vulnerability assessment
requirement that is approved, and effective and subject to compliance by applicable registered entities. The supplemental assessment has
been added to address local enhancements, but without the requirement of a Corrective Action Plan. The comment is suggesting an
alternative threshold or benchmark to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR. The
Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal Impact Assessment documents have
provided the technical foundation and methodologies that can be used to conduct transformer temperature rise calculations for both the
benchmark case and the supplemental case.
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
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69
Question 3
3. The SDT established an 85 A per phase screening criterion for determining which power transformers are required to be assessed for
thermal impacts from a supplemental GMD event in Requirement R10. Justification for this threshold is provided in the revised Screening
Criterion for Transformer Thermal Impact Assessment white paper. Do you agree with the proposed 85 A per phase screening criterion
and the technical justification for this criterion that has been added to the white paper? If you do not agree, or if you agree but have
comments or suggestions for the screening criterion and revisions to the white paper provide your recommendation and explanation.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
No
Document Name
Comment
The technical basis is not clear. The standard references 2‐5 minutes for the supplemental event, but this timeframe is not clearly
referenced within the thermal impact assessment white paper.
Likes 0
Dislikes 0
Response
Thank you for your comment. The thermal impact assessment white paper describes possible ways to carry out a thermal impact
assessment for any given GIC(t) waveform, whether it corresponds to the benchmark or supplemental benchmark waveforms. The
description of the GIC(t) waveforms can be found in the benchmark and supplemental benchmark GMD event white papers.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
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70
Question 3
Both benchmarked and supplemental GMD calculations attempt to limit the hot spot to 172 degrees as a screening criterion. Given the
lower probability of the local 12 V/km GMD enhancements, perhaps the full 200C could be utilized and a screening criteria closer to 150 A
used before a full thermal assessment is undertaken.
Likes 0
Dislikes 0
Response
Thank you for your comment. The probability of occurrence of a local 12 V/peak is the same as the probability of occurrence of spatially
averaged 8 V/km. The impact to the system would be different (local as opposed to wide‐scale). The screening criteria are intended to flag
instances where additional consideration should be given to specific transformers.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
No
Document Name
Comment
Requirement R6 requires a thermal impact assessment for applicable BES power transformers where the maximum effective GIC value
required in Requirement 5, Part 5.1 is 75 A per phase or greater. Requirement R10 requires a supplemental thermal impact assessment for
applicable BES power transformers where the maximum effective GIC value provided in Requirement R9, Part 9.1 is 85 A per phase or
greater. AZPS is concerned that the use of two (2) different thresholds in different analyses (benchmark and supplemental) increases the
potential for inconsistency in the results of the assessments. Accordingly, AZPS suggests using a consistent value per phase in both the
primary and the supplemental assessments. While AZPS would recommend a single 85 A per phase or greater for consistency, its request is
primarily for consistency, which could be achieved at either value.
Likes 0
Dislikes 0
Response
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Question 3
Thank you for your comment. Different screening thresholds were selected because benchmark and supplemental benchmark waveforms
are different and their effects on transformers are different. The temperature thresholds are consistent, i.e., the thermal effects on a
transformer are characterized by peak temperatures.
Eric Shaw ‐ Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; ‐ Eric Shaw
Answer
No
Document Name
Comment
The screening threshold of 75 A per phase used in the benchmark GMD event should also be used in the thermal impact assessment for the
supplemental GMD event because it was determined to be the appropriate value to ensure protection of the transformer.
Likes 0
Dislikes 0
Response
Thank you for your comment. Different screening thresholds were selected because benchmark and supplemental benchmark waveforms
are different and their effects on transformers are different. The temperature thresholds are consistent, i.e., the thermal effects on a
transformer are characterized by peak temperatures.
Chris Scanlon ‐ Exelon ‐ 1
Answer
No
Document Name
Comment
The supplemental GMD waveform used as a justification to develop the 85A screening criteria is not provided, similar to that which is
provided in Figure 2 for the benchmark event in the “Screening Criterion for Transformer Thermal Impact Assessment” white
paper. Therefore, the relationship between the supplemental waveform and hot‐spot results shown in Figure 3 cannot be fully
understood. Additionally, it is not stated which geo‐electric scaling factor (B) was used for the supplemental event.
Likes 0
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2013‐03 Geomagnetic Disturbance Mitigation | October 2017
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Question 3
Dislikes 0
Response
Thank you for your comment. The supplemental GMD waveform is described in the Supplemental GMD Event Description white paper.
Figure 2 is produced as an illustrative example corresponding to a small portion of the benchmark GMD event. The curves shown in Figure 3
of the screening criterion white paper were obtained by carrying out thousands of thermal simulations considering every possible
combination of GICE and GICN as described in Equation (5) of the Thermal Impact Assessment white paper. Beta factors are imbedded in
GICE and GICN and the results in Figure 3 are not specific to any beta factor.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
. There should be a threshold of greater than 500 MVA, similar to CIP standards: High, Medium, and Low impact rating criteria.
Likes 0
Dislikes 0
Response
Thank you for your comment. The applicability for the TPL‐007 standard is to BES transformers that have a high‐side wye‐grounded
connection that is 200 kV and above.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
There should be a threshold of greater than 500 MVA, similar to CIP standards: High, Medium, and Low impact rating criteria.
Likes 0
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73
Question 3
Dislikes 0
Response
Thank you for your comment. The applicability for the TPL‐007 standard is to BES transformers that have a high‐side wye‐grounded
connection that is 200 kV and above.
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
No
Document Name
Comment
Sudden reversal events can occur at far lower theshholds. A high dB/dT can occur during a relatively weak GMD event. Perhaps sensible to
have two typoes of hazard, but if the thresholds are to high, the grid will not be protected. 20 amps per phase would be consistewnt with
INL testing of 138 kV tranasformer in year 2013,. Generator equipment is also susceptible to GMD damage well below 75 amps per phase.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has used consistent geomagnetic field measurements to estimate benchmark events the details of
which are found in the white papers. The thresholds of 75 A/phase and 85 A/phase for transformer impact screening were selected on the
basis of conservative thermal models. For additional explanation please see the response to Resilient Societies at the end of this document.
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
Agree with the proposed screening criteria of 85 A per phase for the Supplemental Event as the threshold for assessing power transformers
since it is consistent with the screening criteria used to establish the 75 A per phase threshold for the Benchmark Event.
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Question 3
Likes 0
Dislikes 0
Response
Thank you for your comment.
Thomas Foltz ‐ AEP ‐ 5
Answer
Yes
Document Name
Comment
AEP agrees with the 85A criterion, but is concerned about the potential duplication of work driven by the need to perform two separate
assessments.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT purposely is requesting two separate thermal assessments be done for transformers that exceed the
GIC thresholds: One for the benchmark event and one for the supplemental event. The supplemental assessment is intended to address
local enhancements. The benchmark assessment may result in a Corrective Action Plan, but the supplemental assessment does not.
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
While the 85 Amps per phase screening criterion is acceptable, it should be noted that the GIC flow values are dependent on the accuracy of
the modeling program from which they are derived. For test cases that have been run using the latest version of GIC modeling and
software, there were significant large currents in excess of 85 Amps in the boundary areas of observation. This behavior is analogous with
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75
Question 3
the slack or swing buses that are used in AC power flow analysis. Specifically, the boundary buses take on whatever resulting flows will
enable a solution for the GIC model flow, without taking into regard any structures that exist beyond these points. As a result, the boundary
current flow conditions are not an accurate representation of the anticipated neutral and phase flow conditions, and if taken at face value,
would result in unnecessary corrective actions to be taken. It is therefore critical that all modeling efforts anticipate these conditions to
occur and ensure that the models are sufficiently adequate in size and scope to provide accurate results within the regions of interest, as
well as to interpret any anomalies that might arise from artificial limitations of the GIC modeling programs.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT agrees that accuracy of models and tools is very important and that their improvement and
validation are the main drivers for the research plan.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
08_SPP TPLTF Discussion Summary on 1st Release TPL‐007‐2.docx8
Comment
please see attached form completed by the TPL‐Task Force9
Likes 0
Dislikes 0
Response
Thank you for providing the TPL‐Task Force information.
8 TPLTF document is found at the end of this document in Attachment 1.
9 TPLTF document is found at the end of this document in Attachment 1.
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Question 3
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
Yes
Document Name
Comment
CenterPoint Energy agrees with the approach used by the SDT to arrive at 85 A per phase as a screening criterion for determining which
power transformers are required to be assessed for thermal impacts from a supplemental GMD event in R10. CenterPoint Energy
appreciates the diligent efforts of the SDT in ensuring consistency between the approach used to develop the screening criterion in R10 and
the approach used to develop the screening criterion in R6.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
Yes
Document Name
Comment
Based on comparing Tables 1 and 2 in the Screen Criterion for Transformer Thermal Impact Assessment, the 85 Ampere screening criteria is
as conservative as the 75 Ampere screening criteria associated with the benchmark event.
Likes 0
Dislikes 0
Response
Thank you for your comment.
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Question 3
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
As the supplemental event is more severe than the benchmark event, we agree that the threshold for transformer thermal assessment
should correspondingly be raised as well. Through analysis, the SDT determined that 85 A per phase was a conservative threshold to apply
for the supplemental event.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Just a question, but have transformer manufacturers been asked if they agree that 85 A is an acceptable threshold for all of their
transformer designs (core‐form, shell‐form), configurations (3‐phase autotransformers, 1‐phase autotransformers, 3‐phase delta‐wye
transformers, etc.), and vintages (old, new)?
Likes 0
Dislikes 0
Response
Consideration of Comments
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Question 3
Thank you for your comment. Transformer manufacturers have been involved with the Geomagnetic Disturbance Task Force (GMDTF) and
their input has informed the development of TPL‐007. The thresholds used in the standard assume single‐phase construction and a healthy
transformer.
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
While the 85 Amps per phase screening criterion is acceptable, it should be noted that the GIC flow values are dependent on the accuracy of
the modeling program from which they are derived. For test cases that have been run using the latest version of GIC modeling and
software, there were significant large currents in excess of 85 Amps in the boundary areas of observation. This behavior is analogous with
the slack or swing buses that are used in AC power flow analysis. Specifically, the boundary buses take on whatever resulting flows will
enable a solution for the GIC model flow, without taking into regard any structures that exist beyond these points. As a result, the boundary
current flow conditions are not an accurate representation of the anticipated neutral and phase flow conditions, and if taken at face value,
would result in unnecessary corrective actions to be taken. It is therefore critical that all modeling efforts anticipate these conditions to
occur and ensure that the models are sufficiently adequate in size and scope to provide accurate results within the regions of interest, as
well as to interpret any anomalies that might arise from artificial limitations of the GIC modeling programs.
“Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event” from the screening criterion document provides a
useful visual, can the drafting team additionally provide a similar chart and the data for the supplemental GMD event?
Likes 0
Dislikes 0
Response
Thank you for your comment. The results of the NERC GMD research plan associated with FERC Order No. 830 may provide more
granularity. The SDT agrees that accuracy of models and tools is very important and that their improvement and validation are the main
drivers for the research plan. The upper bound of hot spot temperatures are provided in Figure 3 of the Screening Criterion for Transformer
Thermal Impact Assessment white paper and in Tables 1 and 2 of Appendix 1 of the same document.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
79
Question 3
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
2013‐03_IB_Comment_Form_June_2017_svm.docx
Comment
Given the use of the 12 V/km geoelectric field amplitude for the supplemental GMD event, the SPP Standards Review Group agrees with the
proposed 85 Amp threshold justified in the Screening Criterion for Transformer Thermal Impact Assessment white paper. We suggest that
the proposed change on page 11 of the white paper stating “because the supplemental waveform has a sharper peak, the peak metallic hot
spot temperatures associated with the supplemental waveform are slightly lower than those associated with the benchmark waveform” be
clarified. In other words, this statement is counterintuitive given that the increased supplemental time‐series waveform peak value implies
higher GIC flows that, when experienced by a transformer will lead potentially higher metallic hot spot temperatures.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT agrees with the comment and has modified the explanation in the white paper as follows: Because
the supplemental waveform has a sharper peak, the peak metallic hot spot temperatures associated with the supplemental waveform for
the same peak current are slightly lower than those associated with the benchmark waveform. In other words, for the same peak current
value, the duration is relatively shorter with the supplemental waveform, and shorter duration means lower temperature. However, higher
peak currents will occur with the supplemental benchmark, therefore, higher peak hot spot temperatures will occur.
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
Based on comparing Tables 1 and 2 in the Screen Criterion for Transformer Thermal Impact Assessment, the 85 Ampere screening criterion
is as conservative as the 75 Ampere screening criteria associated with the benchmark event.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
80
Question 3
Likes 0
Dislikes 0
Response
Thank you for your comment.
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Joe O'Brien ‐ NiSource ‐ Northern Indiana Public Service Co. ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
81
Question 3
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
82
Question 3
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
83
Question 3
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
84
Question 3
Comment
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
85
Question 3
Response
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
86
Question 3
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
87
Question 3
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
88
Question 3
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
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
89
Question 3
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
90
Question 3
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
91
Question 3
Document Name
Comment
Texas RE does not have comments on this question.
Likes 0
Dislikes 0
Response
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
Document Name
Comment
Consistent with our comments above, it should be up to the responsible entity to decide what the appropriate threshold is based on the
responsible entities justification, risk assessment, and risk tolerance level. The whitepapers or any other research can be used to support
the justification.
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Thank you for your comment. The standard provides the flexibility to use technically‐justified technologies and models to carry out
transformer thermal assessments. The temperature thresholds in IEEE STD. 57.91, which inform the 75 A/phase and 85 A/phase screening
thresholds, are prudent industry recommendations that apply to healthy transformers. Applicable entities should ensure that asset
condition and other factors are taken into account in the thermal assessment.
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
92
Question 3
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
93
Question 4
4. The SDT revised the Transformer Thermal Impact Assessment white paper to include the supplemental GMD event. Do you agree with
the revisions to the white paper? If you do not agree, or if you agree but have comments or suggestions on the revisions to the white paper
provide your recommendation and explanation.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
There should be a threshold of greater than 500 MVA, similar to CIP standards: High, Medium, and Low impact rating criteria.
Likes 0
Dislikes 0
Response
Thank you for your comment. The applicability for the TPL‐007 standard is to BES transformers that have a high‐side wye‐grounded connection
that is 200 kV and above.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
There should be a threshold of greater than 500 MVA, similar to CIP standards: High, Medium, and Low impact rating criteria.
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
94
Question 4
Thank you for your comment. The applicability for the TPL‐007 standard is to BES transformers that have a high‐side wye‐grounded connection
that is 200 kV and above.
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
No
Document Name
Comment
NERC’s Screening Criterion for Transformer Thermal Impact Assessment and Transformer Thermal Impact Assessment White Paper state that
TPL‐007‐2 R6 and R10 analyses can in some cases be addressed simply by comparing Screening Criterion for Transformer Thermal Impact
Assessment Table 1 and 2 values to IEEE emergency loading criteria. The statement in footnote 5 of the Transformer Thermal Impact
Assessment White Paper that the “peak GIC(t)” value is to used in this exercise may cause some confusion, however. This appears to be the
“maximum effective GIC” reported in R5.1 and R9.1 of TPL‐007‐2, given that the Screening Criterion for Transformer Thermal Impact
Assessment uses the term “effective GIC” in discussing Tables 1 and 2, but it’s difficult to be certain without a clarification or (better)
harmonization of terms between the standard and its supporting material.
NERC should provide default tables by transformer type (single phase, 5‐legged core 3‐phase, etc) similar to Table 1and 2 for cases in which the
first‐cut process discussed above does not demonstrate that transformers are acceptable as‐is, since the alternatives in the Thermal Impact
Assessment and Transformer Thermal Impact Assessment White Paper will often prove impractical. OEM GIC capability curves are seldom
available, and the same is true for the input data needed for thermal response simulations. Rather than making every GO and TO in North
America seek out consultants with generic information in these respects (if there are any) it would be better to simply present the best
available OK/not‐OK boundaries up‐front.
Likes 0
Dislikes 0
Response
Thank you for your comment. Current knowledge does not allow for generalized tables for different construction types. The tables used in the
standard assume single‐phase construction and a healthy unit. The assessment(s) can use other technically‐justified assumptions.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
95
Question 4
Tables 1 and 2 of the screening criterion white paper represent the best available upper boundaries. The results of the NERC GMD research
plan associated with FERC Order No. 830 may provide more granularity. The SDT agrees that accuracy of models and tools is very important
and that their improvement and validation are the main drivers for the research plan.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
We believe that we need more experience with GMD before moving on to include more time consuming analysis. We also noticed that, Figure
1 and Figure 3 in the Screening Criterion for Transformer Thermal Impact Assessment are on different temperature scales (80‐300 vs 0‐300) so
they are difficult to compare.
Likes 0
Dislikes 0
Response
Thank you for your comment. The Figure 3 y‐axis has been updated. The SDT purposely is requesting two separate thermal assessments be
done for transformers that exceed the GIC thresholds: One for the benchmark event and one for the supplemental event. The distinction
between the benchmark and supplemental thermal assessments is the amplitudes and waveforms of the geoelectric field are different.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
No
Document Name
Comment
The standard references 2‐5 minutes for the supplemental event, but this timeframe is not clearly referenced within the thermal impact
assessment white paper.
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
96
Question 4
Dislikes 0
Response
Thank you for your comment. The thermal impact assessment white paper describes possible ways to carry out a thermal impact assessment
for any given GIC(t) waveform, whether it corresponds to the benchmark or supplemental benchmark waveforms. The description of the
GIC(t) waveforms can be found in the benchmark and supplemental benchmark GMD event white papers.
Chris Scanlon ‐ Exelon ‐ 1
Answer
Yes
Document Name
Comment
Figure 17 indicates that the load is at the 70% level, but the previous paragraph states that the load is at the 75% level. It is unclear whether
the chart or just the description needs to be revised.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has updated the Figure caption.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group agrees with the changes in the Transformer Thermal Impact Assessment white paper, with the exception of
the explanation provided for Table 2 on page 5. Similar to the comment made regarding the counterintuitive language in the Screening
Criterion for Transformer Thermal Impact Assessment white paper, it is not clear why metallic hot spot temperatures are reduced for the
supplemental GMD event for the same effective GIC and transformer bulk oil temperature. Additional clarity on this point would improve the
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
97
Question 4
ability of applicable entities to rely upon the reference data provided. The group recommends adding white paper language similar to that
suggested in Question Q3.
The group would like to highlight that the study of supplemental GMD event conditions may cause a significantly larger number of
transformers to be added for assessed by Transmission Owners and Generator Owners. Given that the analytical tools and modeling software
available for this type of analysis are limited, as well as the fact that most manufacturers supplying power transformers to U.S. customers do
not include data necessary to complete detailed thermal modeling with transformer test reports, the additional effort to satisfy the
supplemental GMD event analysis will be arduous. The group recommends that the SDT consider the reality that these tools are merely in
their infancy across the industry, and additional time to develop, deploy, and train on them should be included in the TPL‐007‐2
implementation plan to complete transformer thermal assessments for the supplemental GMD event.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT agrees with the comment regarding counter intuitive language in the first paragraph and has modified
the explanation in the white paper as follows: Because the supplemental waveform has a sharper peak, the peak metallic hot spot
temperatures associated with the supplemental waveform for the same peak current are slightly lower than those associated with the
benchmark waveform.
The SDT is aware of the current limitations in knowledge and tools.
The supplemental assessment is additional work, but it is necessary to account for the impacts of local enhancements.
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Table 1 and 2 are useful to show the differences between the benchmark event and the supplemental, but some of the figures are not clear
which GMD event was used to generate the GIC(t) time series. Can some additional language be added to clarify the GMD event of the figures
in this document?
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
98
Question 4
Also, there was some inconsistency in axis labels and units between the various figures, which makes it difficult to draw conclusions when
comparing the charts. For example: A/phase versus Amps, minutes versus hours for the time scale. Can these charts be updated with uniform
axis labels and units for comparative purposes?
Likes 0
Dislikes 0
Response
Thank you for your comment. This version of the white paper is intended to illustrate different ways to carry out thermal transformer
assessments. The time series used in the white paper are based on portions of the benchmark time series and are intended for illustrative
purposes only. The Figures in the white papers are sufficiently clear for their intended use.
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
Per FERC’s directive, the transformer thermal assessment was revised to not rely solely on spatially‐averaged data and the SDT modified the
standard to utilize the supplemental GMD event definition for the additional analysis requested by FERC.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Eric Shaw ‐ Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; ‐ Eric Shaw
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
99
Question 4
Comment
We agree with the revisions to the white paper but disagree with the 85 A screening criterion as this may cause damage to the transformers
because a thermal assessment will not be performed until 85 A.
Likes 0
Dislikes 0
Response
Thank you for your comment. Thermal impact on a transformer is quantified against temperature rise, which depends on the peak GIC(t) and
its waveform. The 75 A/phase and 85 A/phase are equivalent in terms of hot spot temperature rise.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
Yes
Document Name
Comment
CenterPoint Energy agrees with the revisions to include the supplemental GMD event in the Transformer Thermal Impact Assessment white
paper.
Likes 0
Dislikes 0
Response
Thank you for your comment.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
100
Question 4
TPLTF Discussion: The group agrees with the changes in the Transformer Thermal Impact Assessment white paper, with the exception of the
explanation provided for Table 2 on page 5. Similar to the comment made regarding the counterintuitive language in the Screening Criterion
for Transformer Thermal Impact Assessment white paper, it is not clear why metallic hot spot temperatures are reduced for the supplemental
GMD event for the same effective GIC and transformer bulk oil temperature. Additional clarity on this point would improve the ability of
applicable entities to rely upon the reference data provided. The group recommends adding white paper language similar to that suggested in
Question Q3.
The group would like to highlight that the study of supplemental GMD event conditions may cause a significantly larger number of
transformers to be added for assessed by Transmission Owners and Generator Owners. Given that the analytical tools and modeling software
available for this type of analysis are limited, as well as the fact that most manufacturers supplying power transformers to U.S. customers do
not include data necessary to complete detailed thermal modeling with transformer test reports, the additional effort to satisfy the
supplemental GMD event analysis will be arduous. The group recommends that the SDT consider the reality that these tools are merely in
their infancy across the industry, and additional time to develop, deploy, and train on them should be included in the TPL‐007‐2
implementation plan to complete transformer thermal assessments for the supplemental GMD event.
10
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request. The existing standard already has a
vulnerability assessment requirement that is approved, and effective and subject to compliance by applicable registered entities. The
supplemental assessment has been added to address local enhancements, but without the requirement of a Corrective Action Plan.
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
10 TPLTF document is found at the end of this document in Attachment 1.
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
101
Question 4
Likes 0
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
102
Question 4
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
103
Question 4
Comment
Likes 0
Dislikes 0
Response
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
104
Question 4
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
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5,
1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
105
Question 4
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
106
Question 4
Likes 0
Dislikes 0
Response
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
107
Question 4
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
108
Question 4
Comment
Likes 0
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
109
Question 4
Response
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
110
Question 4
Document Name
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
111
Question 4
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Thomas Foltz ‐ AEP ‐ 5
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
112
Question 4
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
113
Question 4
Likes 0
Dislikes 0
Response
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
114
Question 4
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
Document Name
Comment
Consistent with our comments above, it should be up to the responsible entity to decide what the appropriate threshold is based on the
responsible entities justification, risk assessment, and risk tolerance level. The whitepapers or any other research can be used to support the
justification.
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Thank you for your comment. See response in Q3.
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
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Question 4
Document Name
Comment
Texas RE does not have comments on this question.
Likes 0
Dislikes 0
Response
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Question 5
5. The SDT developed proposed Requirement R7 to address FERC directives in Order No. 830 for establishing Corrective Action Plan (CAP)
deadlines associated with GMD Vulnerability Assessments (P. 101, 102). Do you agree with the proposed requirement? If you do not agree,
or if you agree but have comments or suggestions for the proposed requirement provide your recommendation and explanation.
Thomas Foltz ‐ AEP ‐ 5
Answer
No
Document Name
Comment
The language used in R7 needs to clarify the type of “year” used in the deadlines of the CAP. Is this “Calendar Year” or “Calendar Months”?
Please clarify. Also, AEP seeks clarification on whether a CAP is required or expected in response to the Thermal Impact Assessments from R6.
If it is, then there may be a conflict in the timelines for the execution of R4 and R6 and the timeline for the development of a CAP as per R7.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT notes that the use of the term “one year” is sufficiently clear. A CAP is not required for individual
transformers that do not meet the requirements of Requirement R6.
Shawn Abrams ‐ Santee Cooper ‐ 1, Group Name Santee Cooper
Answer
No
Document Name
Comment
Santee Cooper has concerns that NERC/FERC is in essence directing entities to implement Corrective Action Plans which violates the Energy
Policy Act of 2005. This revision of TPL‐007 actually has a requirement to implement Corrective Action Plans within a specified period after
their development.
Likes 0
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Question 5
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
Manitoba Hydro cannot adopt R7 as is as it violates The Manitoba Hydro Act. Manitoba Hydro does not support hard coding the timelines for
implementing a corrective action plan in the standard. The timelines are a function of a large number of factors that are out of the control of
the Transmission Planner – including securing the necessary resources. Corporate annual capital spending is limited and is prioritized based on
a number of factors. Securing funding to protect for a 1/100 year event could have lower associated risks to BES reliability than other projects,
meaning timeline discretion for the Transmission Planner to address risks is important.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request, where in Order 830, FERC directed NERC
“to include a deadline of one year from the completion of the GMD Vulnerability Assessments to complete the development of corrective
action plans….[and] to modify Reliability Standard TPL‐007‐1 to include a two‐year deadline after the development of the corrective action
plan to complete the implementation of non‐hardware mitigation and four‐year deadline to complete hardware mitigation.” (FERC Order 830,
PP 101‐102.) The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP cannot be
completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
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Question 5
Document Name
Comment
We have concerns that the first time the evaluation of the TPL‐007 will take place, the corrective action plans may take more time than the R7
requirements. We agree with the deadlines for the second time the evaluation will be done.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard. The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP
cannot be completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
We have concerns that the first time the evaluation of the TPL‐007 will take place, the corrective action plans may take more time than the R7
requirements. We agree with the deadlines for the second time the evaluation will be done.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard. The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP
cannot be completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
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Question 5
Answer
No
Document Name
Comment
Will the TO and GO have any input in the selection of the mitigation actions?
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT expects that the development of the CAP would be a joint effort among the applicable entities.
Requirement 7.5.1 provides a feedback loop for those functional entities who are referenced in the CAP.
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
No
Document Name
Comment
There are specific timetable for implementing the CAP and additional administrative burden placed on the responsible entity if the timetable is
not met; therefore, an additional requirement should be added to the standard to require any functional entity referenced in a CAP to
implement the CAP identified by the responsible entity.
Likes 0
Dislikes 0
Response
Thank you for your comment. An additional requirement is not necessary. The CAP requirements allow for revisions to the CAP if situations
beyond the control of the responsible entity prevent the implementation of the CAP within the stated timetable.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
No
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Question 5
Document Name
Comment
CenterPoint Energy disagrees with the prescriptive timeframes identified in R7.3.1 and R7.3.2. and recommends eliminating R7.3 in its
entirety. Requiring a specific timeframe for mitigation implementation is overly prescriptive and unprecedented for a NERC standard. The
specifics of an implementation timeline should be developed by the responsible entities with more intimate knowledge and understanding of
their systems. The compliance burden of this requirement does not provide commensurate reliability benefits.
If R7.3 is not eliminated as recommended above, CenterPoint Energy supports R7.4 but recommends that the first sentence of R7.4 be
reworded as follows:
R7.4 Be revised if responsible entity cannot implement the CAP within the timetable provided in R7.3.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard. The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP
cannot be completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
No
Document Name
Comment
ISO‐NE is supportive of the proposed R7 as long as any delays with implementing a CAP due to tariff requirements for engaging a stakeholder
planning process when developing system upgrades associated with a CAP are considered to be “beyond the control of the responsible entity.”
Further, ISO‐NE is encouraged that the implementation plan for TPL‐007‐2 includes a one year period between the completion of the
vulnerability assessment in R4 and the completion of any needed CAPs according to R7. ISO‐NE believes that this is in acknowledgement that
the analysis in R4 (and possible in R6) may need to be repeated during the development of CAPs due to the iterative nature of the CAP
development process.
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Question 5
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has added additional language to the end of the “Rationale for Requirement R7.”
Eric Shaw ‐ Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; ‐ Eric Shaw
Answer
No
Document Name
Comment
The hardware mitigation timeline mentioned in the requirement R7 does not address the complexities in building the project like regulatory
approvals, construction clearances on existing equipment, Right of Way requirements, etc.
Likes 0
Dislikes 0
Response
The SDT is responding to a FERC directive in Order 830 to include deadlines for the CAP as a requirement in the standard. The SDT understands
the complexity of implementing the CAP and has addressed the situation where the CAP cannot be completed by the deadline due to
conditions beyond the control of the responsible entities (See R7.4).
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
No
Document Name
Comment
The four‐year hardware implementation deadline in R7.3.2 may be impractical, especially if need for a large number of entities to install GIC
blocking devices leads to extended lead‐times for this equipment. The same issue was thoroughly investigated by the PRC‐025 SDT (see the
Implementation Plan for this standard), leading to an 84‐months deadline, and we recommend that the TPL‐007‐2 SDT follow this precedent.
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Question 5
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard. The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP
cannot be completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
No
Document Name
Comment
We agree with the addition of the proposed Requirement R7 to TPL‐007‐2, however we are concerned with the possible required timeframe
for implementation. Determining appropriate mitigations involves iterative evaluations and solutions. The solutions may involve a number of
TOs and various stakeholder (ISOs/RTOs, governmental bodies, market participants) input may be required as well. The timing requirements
should recognize and allow for delays out of the control of the good‐faith effort of the responsible entity. Given that GIC assessment and
mitigation is a new topic, it is likely that significant time will be required to achieve regional consensus on the appropriate mitigation plan.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to include deadlines for the CAP as a
requirement in the standard. The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP
cannot be completed by the deadline due to conditions beyond the control of the responsible entities (See R7.4).
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
No
Document Name
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Question 5
Comment
OPG does not agree with the implementation deadlines:
R7.2 provides one year for the CAP; this has not been performed before and the timeline may not be realistic.
As stated in the additional comments:
‐ The four years deadline to implement all the hardware mitigation action may provide unfair market advantage to the unaffected/ less
affected TOP, GOP due to the time/resources/financial effort involved. Continued operation should be allowed if there is a shortage of
hardware, or the lead time to design/procure/implement complete hardware solution exceeds the four years duration.
‐ The two years deadline to implement all the non‐hardware solution may provide unfair market advantage to the unaffected/less affected
TOP, GOP, as the implementation for a large scale TOP, GOP will take more time, resources/financial effort and may require commissioning
and studies.
Likes 0
Dislikes 0
Response
Thank you for your comment. It is anticipated that the actual implementation (trigger to activate) of the CAP that includes operational
procedure would only occur during a GMD/GIC event of sufficient size as determined by the assessment. Since GMD events are very rare,
there is less likelihood that market impacts would occur as compared to a ‘regular’ transmission outage or constraint not related to GMD
mitigation.
The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP cannot be completed by the
deadline due to conditions beyond the control of the responsible entities (See R7.4).
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
The revision identifies the need to have implementation of non‐hardware and hardware mitigations within two and four years of CAP
development, respectively. However, there is no technical guidance within the standard that identifies the difference between these
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Question 5
mitigations. According to the FERC Order, GIC blocking or monitoring devices are identified as hardware mitigations. Similar references are
listed within the NERC Geomagnetic Disturbance Planning Guide. We believe these references should be directly incorporated into the
requirement, and replace hardware with GIC reduction or similar devices.
Likes 0
Dislikes 0
Response
Thank you for your comment. The standard is not prescriptive in listing the various hardware and non‐hardware options. Some hardware and
non‐hardware options are listed in Requirement R7.1.
Chris Scanlon ‐ Exelon ‐ 1
Answer
No
Document Name
Comment
The deadlines specified in R7.3.1 and R7.3.2 are ambiguous. Using the term “development” does not offer a specified date to measure the 2‐
or 4‐year installation requirements. To provide clarity for those needing to implement the mitigation, please consider replacing “development
of CAP” with “final approval of CAP by the Planning Coordinator or Transmission Planner.”
R7 does not provide a method to address situations where the responsible entity knows that the selected mitigation cannot meet the 2‐ or 4‐
year deadline during the development of the CAP. As the standard currently states, a CAP would need to be developed with the specified
deadlines in R7.3 and then immediately revised to address the known situations instead of identifying the appropriate timeline during the
development of the CAP. Consider revising R7.4 such that it is not specific to revisions to a CAP only to address these situations.
Likes 0
Dislikes 0
Response
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Question 5
Thank you for your comment. The standard is not prescriptive in providing additional detail to what is essentially an internal process. Entities
may each have different internal processes for the issuance of documents.
The SDT understands the complexity of implementing the CAP and has addressed the situation where the CAP cannot be completed by the
deadline due to conditions beyond the control of the responsible entities (See R7.4).
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits. There should be a threshold of greater than 500 MVA, similar to CIP
standards: High, Medium, and Low impact rating criteria.
Likes 0
Dislikes 0
Response
Thank you for your comment. Whether a particular transformer is relevant to the reliability of the BES is independent of the size of the
transformer and is be determined by the entity responsible for the reliability of the BES in that area. The applicability for the TPL‐007 standard
is to BES transformers that have a high‐side wye‐grounded connection that is 200 kV and above.
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
No
Document Name
Comment
Tri‐State has concern that as written, the TP/PC can create a CAP that the implementing entity (another TO/GO) may have issues with. It seems
the TP/PC has ultimate control on what the CAP is without taking into account that the implementing entity may have other thoughts or
differing opinions. In a situation where a TO/GO states that they are unable to implement a CAP given to them by another TP/PC, what
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Question 5
recourse does the TP/PC have? If an agreement cannot be reached amongst the planning and implementing entities, then what are the next
steps to be taken?
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT expects that the development of the CAP would be a joint effort among the applicable entities.
Requirement 7.5.1 provides a feedback loop for those functional entities who are referenced in the CAP.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits. There should be a threshold of greater than 500 MVA, similar to CIP
standards: High, Medium, and Low impact rating criteria.
Likes 0
Dislikes 0
Response
Thank you for your comment. Whether a particular transformer is relevant to the reliability of the BES is independent of the size of the
transformer and is be determined by the entity responsible for the reliability of the BES in that area. The applicability for the TPL‐007 standard
is to BES transformers that have a high‐side wye‐grounded connection that is 200 kV and above.
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
No
Document Name
Comment
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Question 5
The NSRF believes a definition/example of what “hardware” means in this context is needed. Order 830 in P 82. Says:
NERC states that Reliability Standard TPL‐007‐1 contains “requirements to develop the models, studies, and assessments necessary to build a
picture of overall GMD vulnerability and identify where mitigation measures may be necessary.” NERC explains that mitigating strategies “may
include installation of hardware (e.g., GIC blocking or monitoring devices), equipment upgrades, training, or enhanced Operating Procedures.
Therefore, hardware may only mean GIC blocking or monitoring devices, but it can also include equipment upgrades.
Likes 0
Dislikes 0
Response
Thank you for your comment. The standard is not prescriptive in listing the various hardware and non‐hardware options. Some hardware and
non‐hardware options are listed in Requirement R7.1.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
TPLTF11 Discussion: Given the specificity of the Paragraphs 101 and 102 directives of FERC Order No. 830
Paragraph 44, the group believes that the SDT had little flexibility when developing the proposed language of Requirement R7. The group
agrees with the proposed Requirement R7, as presented. The group would like to reiterate the suggestion that the Supplemental GMD Event
nomenclature be changed to Extreme Value GMD Event, as explained in the group’s discussion of Question Q2.
Likes 0
Dislikes 0
Response
11 TPLTF document is found at the end of this document in Attachment 1.
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Question 5
Thank you for supporting the SPP TPLTF comments on the TPL‐007‐2 standard. The IMAGE dataset is the most complete and comprehensive
data available and is therefore the best data source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there is
no evidence that the local enhancement effect only occurs in high latitudes. Based on the past experiences with the IMAGE data, it is not
expected that the coastal effect has a significant effect on the geomagnetic fields that were used in the extreme value analysis.
12
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
The NSRF believes a definition/example of what “hardware” means in this context is needed. Order 830 in P 82. Says:
NERC states that Reliability Standard TPL‐007‐1 contains “requirements to develop the models, studies, and assessments necessary to build a
picture of overall GMD vulnerability and identify where mitigation measures may be necessary.” NERC explains that mitigating strategies “may
include installation of hardware (e.g., GIC blocking or monitoring devices), equipment upgrades, training, or enhanced Operating Procedures.
Therefore, hardware may only mean GIC blocking or monitoring devices, but it can also include equipment upgrades.
Likes 1
Darnez Gresham, N/A, Gresham Darnez
Dislikes 0
Response
Thank you for your comment. The standard is not prescriptive in listing the various hardware and non‐hardware options. Some hardware and
non‐hardware options are listed in Requirement R7.1.
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
12 TPLTF document is found at the end of this document in Attachment 1.
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Question 5
Document Name
Comment
SRP requests clarification of the phrase "one year" used in 7.2, such as "one calendar year" or "15 months".
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT notes that the use of the term “one year” is sufficiently clear.
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
The deadlines appear to be reasonable (1 year to come up with a CAP when required; 2‐years from CAP determination to implement any non‐
hardware related solutions; 4‐years from CAP determination to implement any hardware related solutions; and exceptions for not meeting
deadlines for factors beyond the control of the responsible entity)
Likes 0
Dislikes 0
Response
Thank you for your comments.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
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Question 5
Comment
Given the specificity of the Paragraphs 101 and 102 directives of FERC Order No. 830 Paragraph 44, the SPP Standards Review Group believes
that the SDT had little flexibility when developing the proposed language of Requirement R7. We agree with the proposed Requirement R7, as
presented.
The group would like to reiterate the suggestion that the Supplemental GMD Event nomenclature be changed to Extreme Value GMD Event, as
explained in the group’s discussion of Question Q2.
Likes 0
Dislikes 0
Response
Thank you for supporting the SPP TPLTF comments13 on the TPL‐007‐2 standard. The IMAGE dataset is the most complete and comprehensive
data available and is therefore the best data source available to support the development of the standard.
Although the four events mentioned in the Supplemental Geomagnetic Event Description document all occurred in northern latitudes, there is
no evidence that the local enhancement effect only occurs in high latitudes. Based on the past experiences with the IMAGE data, it is not
expected that the coastal effect has a significant effect on the geomagnetic fields that were used in the extreme value analysis.
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
IRC agrees with the proposed deadlines as long as any delays with implementing a CAP due to tariff or regional requirements for conducting a
stakeholder planning process when developing system upgrades associated with a CAP are considered to be “beyond the control of the
responsible entity.” Further, IRC is encouraged that the implementation plan for TPL‐007‐2 includes a one year period between the
completion of the vulnerability assessment in R4 and the completion of any needed CAPs according to R7. IRC believes that this is in
13 TPLTF document is found at the end of this document in Attachment 1.
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Question 5
acknowledgement that the analysis in R4 (and possibly R6) may need to be repeated during the development of CAPs due to the iterative
nature of the CAP development process.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has added additional language to the end of the “Rationale for Requirement R7.”
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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Question 5
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
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Question 5
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
Yes
Document Name
Comment
Likes 0
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Question 5
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
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Question 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Document Name
Comment
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Question 5
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
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Question 5
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5,
1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
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
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Question 5
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Likes 0
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Question 5
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
Texas RE acknowledges the SDT made the decision to not require entities have a Corrective Action Plan for the supplemental GMD
Vulnerability Assessment if the System does not meet the performance requirements indicated in Attachment 1. Requirement R8 Part 8.3
requires that if the supplemental GMD Vulnerability Assessment concludes there is Cascading, an evaluation of possible actions designed to
reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) shall be conducted. Texas RE recommends the
responsible entity also conduct an evaluation of possible actions designed to reduce the likelihood or mitigation the consequences and adverse
impacts of voltage collapse and uncontrolled islanding.
Likes 0
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Question 5
Dislikes 0
Response
Thank you for your comment. The SDT notes that Requirement R8.3 is sufficiently clear.
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
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Question 6
6. The SDT developed Requirements R11 and R12 to address FERC directives in Order No. 830 for requiring responsible entities to collect
GIC monitoring and magnetometer data (P. 88; P. 90‐92). Do you agree with the proposed requirements? If you do not agree, or if you
agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
No
Document Name
Comment
Comment #1:
Modify R11 and R12 to replace “Planning Coordinator Area” with the term “respective area” or “responsible area”. This is consistent with TPL‐
007‐1 and TPL‐001‐4. See example below:
R12. Each responsible entity, as determined in Requirement R1, shall implement a process to obtain geomagnetic field data for its respective
Planning Coordinator’s planning area.
Comment #2:
NSFR believes that the reference to “GMD measurement data” in R1 should be changed to align with the language in requirements R11 and
R12. The term GMD measurement data is general and could can be interpreted to include data that is outside the scope of the standard. The
NSRF suggest the following changes to R1:
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 GIC
monitor data and geomagnetic field data GMD measurement data as specified in this standard.
Likes 0
Dislikes 0
Response
Thank you for your comment.
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Question 6
#1. The SDT considers the Planning Coordinators to be the most applicable entity, covering the appropriate area, for implementing processes
related to Requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data, respectively.
#2. The benchmark and supplemental GMD vulnerability assessments in Requirement R1 refers to Requirements R4‐R7 and R8‐R10,
respectively, while the GMD measurement data refers to Requirements R11‐R12, i.e., GMD monitor data and geomagnetic field data. The
SDT has added text in the Rationale for Requirements R11 and R12 that GMD measurement data refers to GMD monitor data and
geomagnetic field data.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT believes that the requirements to implement processes to obtain GIC monitor data and geomagnetic
field data are needed for model validation. The SDT is being responsive to the Standards Authorization Request.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits.
Likes 0
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Question 6
Dislikes 0
Response
Thank you for your comment. The SDT believes that the requirements to implement processes to obtain GIC monitor data and geomagnetic
field data are needed for model validation. The SDT is being responsive to the Standards Authorization Request.
Chris Scanlon ‐ Exelon ‐ 1
Answer
No
Document Name
Comment
The Rationale section for R11 and R12 and the Application Guidelines section for R11 include a statement about using Hall Effect transducers
on the transformer neutrals. There are many technically correct approaches for monitoring geomagnetically induced currents and the
standard should not inadvertently advocate for one method of monitoring over another. The statement should be removed and if necessary,
include a reference to IEEE C57.163 which discusses monitoring.
The R11 and R12 rationale section makes reference to the terms “geomagnetic field data” and “geomagnetic field data product”. What is the
difference? The term “product” should be clarified.
Likes 0
Dislikes 0
Response
Thank you for your comment. The rationale box is intended to provide guidance and not to necessarily advocate a particular method. The
phrase “geomagnetic field data product” is an estimate of the geomagnetic field for a particular geographic location.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
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Question 6
1. We believe the requirements should clarify expected processes once GIC monitoring and magnetometer data is collected. Are
responsible entities expected to include this information in their models that are required for Requirement R2? Are they expected to
provide this information to their Reliability Coordinator for inclusion in its GMD Operating Plan in NERC Reliability Standard EOP‐010‐
1? We believe the associated FERC directives could be incorporated into Requirement R1, which already requires an entity‐
coordinated process to identify the collection of GMD data measurements. We see benefits in enhancing Requirement R1 to include
subparts for maintaining models, performing studies for GMD Vulnerability Assessments, and GIC monitoring and magnetometer data
collection, including within its associated Violation Severity Limits.
2. The reference to the collection of data for the entire Planning Coordination Area is too broad and burdensome for the applicability of
these requirements. We believe the identified collection area should be reflective of the applicability, to that of the responsible
entity’s planning area.
Likes 0
Dislikes 0
Response
Thank you for your comment.
1.
The SDT is being responsive to the Standards Authorization Request to collect geomagnetically induced current monitoring and
magnetometer data as necessary to enable model validation and situational awareness. The commenter is suggesting changes to EOP‐
010‐1, which is an existing standard and outside the scope of the SAR.
2.
The SDT considers the Planning Coordinators to be the most applicable entity, covering the appropriate area, for implementing
processes related to requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC, Group Name Southern Company
Answer
No
Document Name
Comment
1. Paragraph 2, page 11 of 42 of proposed TPL‐007‐2, under GMD Measurement Data Process (blue box) – the Drafting Team states that
“ Technical considerations for GIC monitoring are contained in Chapter 6 of the 2012 Special Reliability...” This information is
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Question 6
contained in Chapter 9 and not in Chapter 6 of the Interim Report. Please update this section as well as the first sentence immediately
under R11 in page 38 of 42. In addition, we recommend that the Drafting Team includes a link to the report as it is difficult to find.
2. Requirement 12, page 12 or 42, requires that “Each responsible entity...shall implement a process to obtain geomagnetic field data for
its Planning Coordinator’s planning area.” This requirement appears to be in direct contradiction to the last sentence contained inside
the ‘blue box’ same page; which states: “The geomagnetic field data product does not need to be derived from a magnetometer or
observatory within the Planning Coordinator’s planning area”. We request clarification. And, if the magnetometer data needs to be
extrapolated, we recommend that the drafting team provides guidance.
3. Draft 1 of TPL‐007‐2, page 38 of 42, under Monitor specifications –
i. monitor data range (i.e., ‐500 A to +500 A CT), will this monitor specification be a recommendation or requirement? We
recommend the Drafting Team to provide clarification. Note this section references the NERC 2012 GMD report and in the
2012 report it is stated “The DC sensor should accommodate at least +/‐ 500 amps of DC current...”. Referencing the 2012
GMD Report creates confusion.
ii. ambient temperature ratings, we recommend the SDT to provide clarification; i.e., does the monitor need to include the ability
to measure ambient temperature and should we log the station ambient temperatures.
Likes 0
Dislikes 0
Response
Thank you for your comment.
1. The SDT would like to express our thanks for pointing out the typo in the rationale box for requirements R11 and R12 with respect to
chapter number in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk‐Power
System (NERC 2012 GMD Report).
2. The SDT considers the Planning Coordinators to be the most applicable entity, covering the appropriate area, for implementing
processes related to requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data.
The phrase “geomagnetic field data product” is an estimate of the geomagnetic field for a particular geographic location. The standard
allows flexibility to collect the geomagnetic field data or use the geomagnetic field data product to obtain the data as necessary.
3. The text in the Guidelines and Technical Basis related to requirement R11, which refers to the technical considerations for GIC
monitoring based on the NERC 2012 GMD Report [Chapter 9] as well as the Intermagnet Technical Reference Manual, provides
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Question 6
guidelines and recommendations that are not part of the TPL‐007‐2 requirements. The “monitor” specifications only need to consider
the ambient ratings of the monitoring equipment based on their location.
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
No
Document Name
Comment
Depending on the size of the planning area, one GIC and magnetometer value may not provide sufficient data to accurately provide model
validation. Some additional guidance would also be helpful for determining where to place monitoring equipment so that the equipment is
installed in a location that can provide meaningful data. NV Energy would prefer the SDT consider adding additional details on determining
the placement of equipment and consider adding detail to add more than one monitoring equipment when appropriate.
R11 and R12 requires data to be collected, but does not require anything to be done with the data. With no requirement to do anything with
data collected, it seems like these two requirements place an unnecessary task on entities. Additionally, R12 allows entities to collect
geomagnetic from sources such as observatories operated by the US Geological Survey. With no requirements to do anything with the data,
R12 is asking entities to log onto a website and periodically collect data. NV Energy would like to see these standards expanded upon to
require this data to be collected and then used for GMD model validation.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to require responsible entities to collect
geomagnetically induced current monitoring and magnetometer data as necessary to enable model validation and situational awareness.
The NERC 2012 GMD Report and the Intermagnet Technical Reference Manual provide considerations for developing a process to obtain GIC
monitor data and are summarized under Requirement R11 in the Guidelines and Technical Basis section of the TPL‐007‐2 standard.
Eric Shaw ‐ Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; ‐ Eric Shaw
Answer
No
Document Name
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Question 6
Comment
One GIC monitor and magnetometer value in the Planning Coordinator's planning area does not provide enough data to enable model
validation and situational awareness
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT considers the Planning Coordinators to be the most applicable entity, covering the appropriate area,
for implementing processes related to requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic
field data.
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
Magnetometers data are already available from Natural Resources Canada and from Universities research groups, therefore, there is no need
to collect them.
In the control room, Hydro‐Quebec monitors and collects the impact of GMDs by using voltage distortion level. GIC currents are also collected
at different location on the network but they are not used in the control room. The acquisition of these data should be added to the EOP‐
010‐1 reliability standard under the RC supervision and the RC shall transmit them as requested by the PC.
Hydro‐Quebec supports initiatives that can be used to monitor and validate, with real measures, the GMD’s impact on the network.
Likes 0
Dislikes 0
Response
Thank you for your comment. As described in the Rationale Box (blue box) on Rationale for Requirements R11 and R12, sources of
geomagnetic field data include: Observatories such as those operated by U.S. Geological Survey, Natural Resources Canada, research
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Question 6
organizations, or university research facilities; Installed magnetometers; and Commercial or third‐party sources of geomagnetic field data.
The SDT is being responsive to the Standards Authorization Request. The comment is suggesting changes to EOP‐010‐1, which is an existing
standard and outside the scope of the SAR.
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
No
Document Name
Comment
SRP supports AZPS’s response to question 6.
Likes 0
Dislikes 0
Response
Thank you for your comment. Since the GIC monitoring data collection requirement is to have at least one GIC monitor located in the Planning
Coordinator's planning area, and not each transmission owner being required to collect GIC monitoring data, the SDT does not believe the
exemption from the GIC monitoring data collection requirement discussed in Paragraph 91 of FERC Order No. 830 is applicable. The SDT
considers the Planning Coordinators to be the most applicable entity, covering the appropriate area, for implementing processes related to
requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data, and hence the SDT sees no
need for a threshold. The SDT supports use of different thresholds for the benchmark and the supplemental GMD Vulnerability Assessments.
The collection of GIC monitor data and geomagnetic field data per Requirements R11 and R12 provide a basis for enabling model validation
and situational awareness, as discussed in FERC order 830. As such, GIC data collection is necessary regardless of any GIC threshold.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
Document Name
Comment
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Question 6
Magnetometers data are already available from Natural Resources Canada and from Universities research groups, therefore, there is no need
to collect them.
In the control room, Hydro‐Quebec monitors and collects the impact of GMDs by using voltage distortion level. GIC currents are also collected
at different location on the network but they are not used in the control room. The acquisition of these data should be added to the EOP‐
010‐1 reliability standard under the RC supervision and the RC shall transmit them as requested by the PC.
Hydro‐Quebec supports initiatives that can be used to monitor and validate, with real measures, the GMD’s impact on the network.
Likes 0
Dislikes 0
Response
Thank you for your comment. As described in the Rationale Box (blue box) on Rationale for Requirements R11 and R12, 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.
The SDT is being responsive to the Standards Authorization Request. The comment is suggesting changes to EOP‐010‐1, which is an existing
standard and outside the scope of the SAR.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
No
Document Name
Comment
Per Paragraph 91 of FERC Order No. 830, a transmission owner should be able to apply for an exemption from the GIC monitoring data
collection requirement if it demonstrates that no or little value would be added to Planning and Operations. The capability to request such
exemption is not, however, clearly indicated within Requirements R11 and R12. AZPS respectfully recommends that such language be
included.
AZPS further recommends that the SDT utilize language similar to that included in Requirement R10, which includes language that limits the
need to [conduct a supplemental thermal impact assessment for applicable BES power transformers where the maximum effective GIC value
provided in R9, Part 9.1 is 85 A per phase or greater]. AZPS proposes that similar language be added in Requirements R11 and R12 so that
these requirements only apply where the maximum effective GIC value of applicable BES power transformers provided in R9, Part 9.1 is 85 A
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Question 6
per phase or greater. Such would ensure that the same operational threshold is applied throughout these related requirements, providing
consistency and an established threshold for determining need from the operational/planning perspective.
Additionally, as noted in AZPS’s comments to question 3 above, AZPS’s request here is primarily for consistency and, while it recommends a
threshold of 85 A per phase or greater, its recommendation could be achieved through the consistent application of that value or the 75 A per
phase or greater.
Likes 0
Dislikes 0
Response
Thank you for your comment. Since the GIC monitoring data collection requirement is to have at least one GIC monitor located in the Planning
Coordinator's planning area, and not each transmission owner being required to collect GIC monitoring data, the SDT does not believe the
exemption from the GIC monitoring data collection requirement discussed in Paragraph 91 of FERC Order No. 830 is applicable. The SDT
considers the Planning Coordinators to be the most applicable entity, covering the appropriate area, for implementing processes related to
requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data, and hence the SDT sees no
need for a threshold. The SDT supports use of different thresholds for the benchmark and the supplemental GMD Vulnerability Assessments.
The collection of GIC monitor data and geomagnetic field data per Requirements R11 and R12 provide a basis for enabling model validation
and situational awareness, as discussed in FERC order 830. As such, GIC data collection is necessary regardless of any GIC threshold.
Different screening thresholds were selected because benchmark and supplemental benchmark waveforms are different and their effects on
transformers are different. The temperature thresholds are consistent, i.e., the thermal effects on a transformer are characterized by peak
temperatures.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
It’s nice to collect data but there’s no requirement to do anything with the data, like perform model benchmarking. Collecting data from a
single transformer and a single magnetometer may be insufficient to perform any reasonable benchmarking of GMD models. Perhaps this
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Question 6
could be written in a style closer to MOD‐033, for GMD model validation. The Transmission Planner would document their model
validation process.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to collect geomagnetically induced current
monitoring and magnetometer data as necessary to enable model validation and situational awareness.
The NERC 2012 GMD Report and the Intermagnet Technical Reference Manual provide considerations for developing a process to obtain GIC
monitor data and are summarized under Requirement R11 in the Guidelines and Technical Basis section of the TPL‐007‐2 standard.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
No
Document Name
Comment
The SDT should consider additional details on placement of the monitoring equipment to help guide the installations, similar to PRC‐002 and
DME. Or, the responsibility for equipment placement guidelines could be delegated (assigned) to the PC to develop at a more local
level. Having wide‐open equipment monitoring requirements may lead to a lot of wasted investment or inefficient monitoring.
Likes 0
Dislikes 0
Response
Thank you for your comment. Technical considerations for GIC monitoring are contained in the NERC 2012 GMD Report as well as the
Intermagnet Technical Reference Manual provide considerations to address during the development of a process for obtaining GIC monitor
are provided under Requirement R11 in the Guidelines and Technical Basis section.
Thomas Foltz ‐ AEP ‐ 5
Answer
No
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Question 6
Document Name
Comment
American Electric Power does not believe R11 and R12 are explicitly clear in their intent, or state exactly who is required to meet the
obligations. The latter may perhaps be inferred by R1, however AEP requests clarity and specificity within R11 and R12 themselves.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to develop revisions to the standard to
require responsible entities to collect geomagnetically induced current monitoring and magnetometer data as necessary to enable model
validation and situational awareness.
The NERC 2012 GMD Report and the Intermagnet Technical Reference Manual provide considerations for developing a process to obtain GIC
monitor data and are summarized under Requirement R11 in the Guidelines and Technical Basis section of the TPL‐007‐2 standard.
The individual or joint responsibilities of the applicable entities are defined per Requirement R1.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Despite the added cost to implement additional monitoring and data collection, the SPP Standards Review Group agrees that the SDT
developed a reasonable approach to the FERC directives in Order No. 830 Paragraph 88.
Likes 0
Dislikes 0
Response
Thank you for your comment.
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Question 6
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
FERC required additional data for model validation and situational awareness purposes. The SDT developed requirements allow for the
collection of GIC data and magnetometer data (which could come from existing monitoring equipment where available and appropriate) as
opposed to necessarily mandating installation of new equipment to obtain the specified data. Responsible entities can thus partner with
government agencies or research facilities that operate magnetometers to obtain some of the required data.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
Yes
Document Name
Comment
CenterPoint Energy agrees with the proposed requirement as written. Furthermore, CenterPoint Energy supports the Commission’s
determination in P. 92 that requiring data rather than requiring installation of GIC monitors and magnetometers affords greater flexibility
while still obtaining benefits. However CenterPoint Energy would not support any revisions that would require installation of devices or the
release of entity’s protected information.
Likes 0
Dislikes 0
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Question 6
Response
Thank you for your comment.
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Will this result in a directive for a GO or TO to install GIC monitoring, or will the responsible entity simply get data from existing monitors in its
area?
Likes 0
Dislikes 0
Response
Thank you for your comment. The individual or joint responsibilities of the applicable entities are defined in Requirement R1 and a process to
obtain GIC monitor data in Requirement R11.
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Comment #1:
Modify R11 and R12 to replace “Planning Coordinator Area” with the term “respective area” or “responsible area”. This is consistent with TPL‐
007‐1 and TPL‐001‐4. See example below:
R12. Each responsible entity, as determined in Requirement R1, shall implement a process to obtain geomagnetic field data for its respective
Planning Coordinator’s planning area.
Comment #2:
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Question 6
NSFR believes that the reference to “GMD measurement data” in R1 should be changed to align with the language in requirements R11 and
R12. The term GMD measurement data is general and could can be interpreted to include data that is outside the scope of the standard. The
NSRF suggest the following changes to R1:
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 GIC
monitor data and geomagnetic field data GMD measurement data as specified in this standard.
Likes 1
Darnez Gresham, N/A, Gresham Darnez
Dislikes 0
Response
Thank you for your comment.
#1. The SDT considers the Planning Coordinator’s planning area to be the most appropriate area for implementing processes related to
Requirements R11 and R12 to obtain GIC monitor data from at least one GIC monitor and geomagnetic field data, respectively.
#2. Requirement R1 is sufficiently clear. The benchmark and supplemental GMD vulnerability assessments in Requirement R1 refers to
Requirements R4‐R7 and R8‐R10, respectively, while the GMD measurement data refers to Requirements R11‐R12, i.e., GIC monitor data and
geomagnetic field data. The SDT has added text in the Rationale for Requirements R11 and R12 that GMD measurement data refers to GIC
monitor data and geomagnetic field data.
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
In R12, it is not clear how much geomagnetic field data, from a time & space perspective, the responsible entity would be required to obtain
for its Planning Coordinator Planning Area.
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Question 6
Likes 0
Dislikes 0
Response
Thank you for your comment. Requirement R12 does not specify how geomagnetic field data is to be collected from a time and space
perspective. The individual or joint responsibilities of the applicable entities are defined in Requirement R1, including responsibilities related
to implementation of a process for obtaining geomagnetic field data in Requirement R12.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
TPLTF14 Discussion: Despite the added cost to implement additional monitoring and data collection, the group agrees that the SDT developed
a reasonable approach to the FERC directives in Order No. 830 Paragraph 88.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
14 TPLTF document is found at the end of this document in Attachment 1.
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Question 6
This will help refine future assessment requirements as to how applicable the Benchmark and Supplemental Event screening criteria are in
comparison compared to actual recorded GMD events.
Likes 0
Dislikes 0
Response
Thank you for your comment.
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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Question 6
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
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Question 6
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
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Question 6
Dislikes 0
Response
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 6
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
Yes
Document Name
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Question 6
Comment
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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Question 6
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Consideration of Comments
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Question 6
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
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165
Question 6
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Richard Vine ‐ California ISO ‐ 2
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Question 6
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Brandon McCormick ‐ Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 5, 6, 4, 3; David Schumann, Florida
Municipal Power Agency, 5, 6, 4, 3; Ginny Beigel, City of Vero Beach, 3; Jeffrey Partington, Keys Energy Services, 4; Joe McKinney, Florida
Municipal Power Agency, 5, 6, 4, 3; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power Agency,
5, 6, 4, 3; Tom Reedy, Florida Municipal Power Pool, 6; ‐ Brandon McCormick, Group Name FMPA
Answer
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Question 6
Document Name
Comment
We appreciate the SDT effort to satisfy the requirement of FERC Order No. 830 for the collection of GIC and Magnetometer Data. Currently,
R11 and R12 only say to collect the data. We would encourage the drafting team to add language to R11 and R12 that the process document
developed by the responsible entity point to the amount of data required, who collects it, who to give it to, and how long to maintain it.
Likes 0
Dislikes 0
Response
Thank you for your comment. The individual or joint responsibilities of the applicable entities are defined in Requirement R1 and to
implement a process for obtaining GIC monitoring data and geomagnetic field data in Requirements R11 and R12, respectively.
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
Since the Rationale for Requirements R11 and R12 use the term “as necessary”, Texas RE recommends adding the term “as necessary” as a
periodicity to the language of Requirements R11 and R12.
Requirement R11 requires a GIC monitor located in the Planning Coordinator’s planning area. The map showing the USGS observatories
(https://geomag.usgs.gov/monitoring/observatories/) indicates that there is not a USGS monitor in each PC’s planning area. There may be
monitoring data available for GIC in the PC’s planning area that is not located within the planning area. Texas RE recommends revising the
language to say “Each responsible entity…..from at least one GIC monitor that is monitoring equipment within the Planning Coordinator’s
planning area for each earth model represented…..”.
Likes 0
Dislikes 0
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Question 6
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request to require responsible entities to collect
geomagnetically induced current monitoring and magnetometer data as necessary to enable model validation and situational awareness.
The standard requires data to be obtained 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 (Requirement R11) and geomagnetic field data for its Planning
Coordinator’s planning area (Requirement R12).
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Question 7
7. Do you agree with the proposed Implementation Plan for TPL‐007‐2? If you do not agree, or if you agree but have comments or
suggestions for the Implementation Plan provide your recommendation and explanation.
Kristine Ward ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Answer
No
Document Name
Comment
Comments: The effective date of the revised Standard being only 3 months after FERC’s approval is too short. There is no need to rush this
new Standard as there are substantial revisions. Seminole recommends a minimum of 12 months after approval
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
There should be trial period for industry to gain understanding and knowledge of GMD before implementing a standard.
Likes 0
Dislikes 0
Response
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Question 7
Thank you for your comment. The existing standard is already approved and the SDT is being responsive to the Standards Authorization
Request. Requiring a trial period is outside the scope of this SDT.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
No
Document Name
Comment
AZPS requests more clarity regarding the due date of the supplemental assessment (TPL‐007‐2 Requirement R8). If the effective date of TPL‐
007‐2 is before the January 1, 2021 and the studies are performed concurrently, what is the due date of the supplemental assessment (TPL‐
007‐2 Requirement R8)? According to the implementation plan, both assessments would be due 42 months after the effective date of TPL‐
007‐2. If such is an accurate statement of the appropriate study deadlines, AZPS requests that the SDT clarify this in its guidance, FAQs, or
other document.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
Document Name
Comment
See comments for Question 1.
Likes 0
Dislikes 0
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171
Question 7
Response
Thank you for your comment, see response in Q1.
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
No
Document Name
Comment
It is not clear why there is a difference in compliance implementation dates for the various requirements between the two Implementation
Plan options. It would seem logical that they both would have the same compliance implementation date with respect to the effective date of
the Standard.
There does not appear to be a compliance date for R6 if TPL‐007‐2 becomes effective on or after January 1, 2021.
TPL‐007‐1 has a compliance date for R5 on January 1, 2019. It is not clear what this date would be if the new standard becomes effective
before that date.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
See comments for Question 1.
Likes 0
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Question 7
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
No
Document Name
Comment
The current implementation plan doesn’t contain an implementation date for R1 which implies an effective date of the first day of the first
calendar quarter that is three month after FERC approval. Planning Coordinators will need time to update their document identifying
individual and joint responsibility to include the supplemental GMD Vulnerability Assessment and a process to obtain GMD measurement
data. Entities should be given a minimum of 6 months after the approval of the standard to update R1 documentation since it does require
coordination with Transmission Planners.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Larisa Loyferman ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
No
Document Name
Comment
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Question 7
CenterPoint Energy disagrees with the proposed Implementation Plan for TPL‐007‐2. CenterPoint Energy recommends delaying the
implementation of Requirement 8 through 10 until after one complete cycle of Requirements R4 through R6. CenterPoint Energy’s
recommendation is based on the following:
The efforts already required for compliance with TPL‐007‐1 that necessitate data sharing, model building, process creation, and first‐
of‐its‐kind analysis are already significant. The analysis tools needed for completion of the Vulnerability Assessment required by TPL‐
007‐1 are not available in the industry at this time. The NERC GMD Task Force identified Task 7 to develop tools for system‐wide
harmonic assessment; however, this task is not scheduled to be complete until the fourth quarter of 2019.
The additional efforts necessary to comply with Requirements R8 – R10 within the same timeline will result in an unreasonable
resource burden that does not provide commensurate reliability benefits.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has proposed the phasing‐in of version 2 into the timing of the implementation of version 1, depending
on the timing of approval of the revised standard by FERC.
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
No
Document Name
Comment
ISO‐NE does not agree with the January 2021 transition date in the implementation plan. The concern is that the base case used for TPL‐007‐
01 will be obsolete by January 2023 according to the requirement to use a case within the Near‐Term Transmission Planning Horizon. Note
that the timing for meeting R2 and R4 in TPL‐007‐1 and the desire to model an as known system as possible (e.g. minimizing the need for case
changes as new projects will have been approved and retirements have been announced) has driven ISO‐NE to select a study year of 2023.
This will create issues when stakeholders review the results and may cause additional study and case building efforts during the first cycle for
meeting the new TPL‐007‐1 reliability standard. ISO‐NE proposes that the transition deadline date should be changed from January 2021 to
January 2019 or July 2019 so that the base case used for testing with the benchmark waveform according to the known timing for TPL‐007‐1
can be used for testing the supplemental waveform.
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Question 7
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
No
Document Name
Comment
Consistent with our comments above
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
No
Document Name
Comment
The four‐year hardware implementation deadline in R7.3.2 may be impractical, especially if need for a large number of entities to install GIC
blocking devices leads to extended lead‐times for this equipment. The same issue was thoroughly investigated by the PRC‐025 SDT (see the
Implementation Plan for this standard), leading to an 84‐months deadline, and we recommend that the TPL‐007‐2 SDT follow this precedent.
Likes 0
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Question 7
Dislikes 0
Response
Thank you for your comment. The SDT notes that the development of the CAP allows one year and four years for completing the hardware
mitigation. The standard has included a process for reporting delays in implementation beyond the deadline due to factors outside of the
entity’s control (R7.4).
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
No
Document Name
Comment
The compliance date for Requirement R9 (if TPL‐007‐2 becomes effective before January 1, 2021) is too short. We would propose a
compliance date of 12 months after the effective date of Reliability Standard TPL‐007‐2 if it becomes effective before January 1, 2021.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Chris Scanlon ‐ Exelon ‐ 1
Answer
No
Document Name
Comment
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Question 7
The implementation plan is not clear on whether the Standard Drafting Team intends on replacing the effective dates of TPL‐007‐1 for all
requirements with the effective date and compliance dates for TPL‐007‐2 or carrying forward the TPL‐007‐1 effective dates. Please provide
additional language to outline the SDT’s intent with the timing between TPL‐007‐1 effective dates and TPL‐007‐2 effective dates.
Similarly, as the implementation plan is written, under certain situations, the effective dates for performing the assessments for the
supplemental event may not necessarily align with the periodicity for performing the assessments for the benchmark event currently required
under TPL‐007‐1, which may create an unnecessary burden for performing assessments on separate cycles.
Likes 0
Dislikes 0
Response
Thank you for your comment. The intent of the TPL‐007‐2 implementation plan is to integrate the new requirements with the GMD
assessment process that is being implemented through TPL‐007‐1. The implementation plan phases in the new requirements based on the
effective dates of TPL‐007‐1 and the earliest possible date that the FERC approval dates of the new revised standard could occur.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
Current implementation dates for requirements 2‐6 are January 1, 2021. The implementation plan for TOP‐007‐2 is confusing. In one bullet
it says the effective date is on or before January 1, 2021, and the bullit below it says the effective date is after January 1, 2021.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan. Current implementation dates for requirements R2, R3, and R4 is January 2022 and R5 is January 2019 and R6 is January 2021. The
intent of the TPL‐007‐2 implementation plan is to integrate the new requirements with the GMD assessment process that is being
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Question 7
implemented through TPL‐007‐1. The implementation plan phases in the new requirements based on the probable FERC approval dates of
the new revised standard.
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
No
Document Name
Comment
As currently written, the implementation plan can actually shorten the current timeframes to become compliant with TPL‐007 requirements.
It seems that if TPL‐007‐2 was approved and became effective 7/1/18, then R1, R2, and R5 would also be effective 7/1/18. However, TPL‐007‐
1 R5 isn't supposed to go into effect until 7/1/19. The TPL‐007‐2 implementation plan should be revised so that entities have at least until the
TPL‐007‐1 effective dates to comply with requirements R1‐R7. Tri‐State recommends adding language similar to the commonly used "shall
become effective on the later of XXXX or the first day of the XX calendar quarter". That would prevent entities from losing time they might
have already planned on having to become complaint with R2‐R7.
Likes 0
Dislikes 0
Response
Thank you for your comment. The intent of the TPL‐007‐2 implementation plan is to integrate the new requirements with the GMD
assessment process that is being implemented through TPL‐007‐1. The implementation plan phases in the new requirements based on the
effective dates of TPL‐007‐1 and the earliest possible date that the FERC approval dates of the new revised standard could occur. If so, the
effective dates to be compliant with Requirements R1 and R2 would be extended by six months and Requirement R5 would be the same as
the effective date. Although possible, it is not likely.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
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Question 7
Current implementation dates for requirements 2‐6 are January 1, 2021. The implementation plan for TOP‐007‐2 is confusing. In one bullet,
it says the effective date is on or before January 1, 2021, and the bullet below it says the effective date is after January 1, 2021.
Likes 0
Dislikes 0
Response
Thank you for your comment. The intent of the TPL‐007‐2 implementation plan is to integrate the new requirements with the GMD
assessment process that is being implemented through TPL‐007‐1. The implementation plan phases in the new requirements based on the
effective dates of TPL‐007‐1 and the earliest possible date that the FERC approval dates of the new revised standard could occur. The current
compliance dates for TPL‐007‐1 are not as stated. Please refer to the NERC website for the enforcement dates.
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
No
Document Name
Comment
We favor a combined standard for GMD and HEMP events, so that the U.S. electric grid is actually protected against severe solar storms and
so it can aid in deterrence, protecton and recovery from both natural and manmade electromagnetic oulse hazards.
Likes 0
Dislikes 0
Response
Thank you for your comment. Combining GMD with HEMP is outside the scope of this SDT.
Thomas Foltz ‐ AEP ‐ 5
Answer
Yes
Document Name
Comment
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Question 7
AEP would like clarity on the type of duration (e.g. Calendar Year or Calendar Month) being proposed. This is not explicit in the current draft
of the implementation plan.
Likes 0
Dislikes 0
Response
Thank you for your comment. The referenced months that do not use “calendar month” are simply a count of the months following approval.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
TPLTF15 Discussion: The group agrees with the proposed Implementation Plan for TPL‐007‐2 and does not see any conflicts with the order by
which the phased requirements become effective. However, given the lack of available tools, absence of thermal modeling‐related data from
transformer manufacturers, and the significant training that will be necessary to properly execute transformer thermal assessments, the
group believes that the implementation period for Requirement R10 should be at least 48 months after the standard is approved. This
suggested implementation period is consistent with the existing implementation period for Requirement R6 (transformer thermal assessment
for benchmark GMD event) and should allow sufficient time for many more transformers that may be observed to exceed the supplemental
GMD event screening criterion.
Likes 0
Dislikes 0
Response
Thank you for your comment.
15 TPLTF document is found at the end of this document in Attachment 1.
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Question 7
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
ISO‐NE does not join this response.
Likes 0
Dislikes 0
Response
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
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Question 7
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 7
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
Yes
Document Name
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Question 7
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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184
Question 7
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
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
Consideration of Comments
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Question 7
Document Name
Comment
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
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186
Question 7
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
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187
Question 7
Response
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Consideration of Comments
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Question 7
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group agrees with the proposed Implementation Plan for TPL‐007‐2 and does not see any conflicts with the order
by which the phased requirements become effective. However, given the lack of available tools, absence of thermal modeling‐related data
Consideration of Comments
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189
Question 7
from transformer manufacturers, and the significant training that will be necessary to properly execute transformer thermal assessments, the
group believes that the implementation period for Requirement R10 should be at least 48 months after the standard is approved. This
suggested implementation period is consistent with the existing implementation period for Requirement R6 (transformer thermal assessment
for benchmark GMD event) and should allow sufficient time for many more transformers that may be observed to exceed the supplemental
GMD event screening criterion.
Likes 0
Dislikes 0
Response
Thank you for your comment.
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 7
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
Texas RE appreciates the SDT’s efforts to develop a workable Implementation Plan (IP) for TPL‐007‐2 that reflects the modifications required
by FERC’s directives in Order No. 830 while attempting to maintain the original five‐year phased implementation timeframe established for
TPL‐007‐1. As presently drafted, however, the proposed TPL‐007‐1 IP attempts to coordinate the existing TPL‐007‐1 deadlines with the new
TPL‐007‐2 requirements by shortening the compliance dates under the version 2 standard by 18 months in circumstances in which FERC
approves the new version before January 1, 2021. This appears roughly coordinated with the May 2018 filing deadline established in Order
No. 830.
While Texas RE does not object to this approach, Texas RE notes that the TPL‐007‐2 IP, as currently drafted, is complex and could produce
several unintended consequences as entities interpret their layered compliance obligation timelines. In particular, the proposed IP requires
entities to now potentially track two IPs. For instance, the TPL‐007‐2 IP is drafted such that the enforceable dates for TPL‐007‐1 R2, presently
July 1, 2018, remain under the original IP. While this is a reasonable approach, the SDT should consider explicitly incorporating the deadlines
from the TPL‐007‐1 IP into the TPL‐007‐2 IP, at least by reference. By taking this approach, the SDT can ensure that responsible entities
clearly understand the relevant compliance dates for each Standard requirement and eliminate confusion regarding which compliance dates
are subject to revision and which are not.
Such additional clarity may be particularly important in connection with the enforceable dates for TPL‐007‐2 R5. Under the TPL‐007‐1 IP, TPL‐
007‐1 R5 is enforceable on January 1, 2019. The proposed TPL‐007‐2 IP does not address the enforceable date for TPL‐007‐2 R5. As such,
entities are presumably required to comply with TPL‐007‐2 R5 on the effective date of the Standard. Texas RE presumes that the SDT
anticipates that TPL‐007‐2 will not be effective and enforceable prior to January 1, 2019 given the May 2018 filing deadline, the period for
FERC approval, the 60‐day period for the FERC order to become final, and the fact that the Standard does not become effective until the first
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Question 7
day of the calendar quarter three months after the FERC order is final. However, given the status of this project, it is possible that NERC may
wish to submit a revised TPL‐007‐2 prior to May 2018. For instance, suppose NERC submits a proposal in January 2018 and FERC issues its
order in April 2018. The FERC order would become final by July 1, 2018. As such, TPL‐007‐2 would become enforceable on October 1,
2018. As a result, entities’ compliance deadlines would be inadvertently accelerated from January 1, 2019 to October 1, 2018. The SDT
should avoid this possibility by clearly delineating within the TPL‐007‐2 IP which TPL‐007‐1 enforceable dates remain applicable.
Conversely, the proposed TPL‐007‐2 IP can be interpreted to extend the compliance deadline for the Benchmark GMD study required under
TPL‐007 R4 by five years. In particular, the TPL‐007‐2 IP does not specify an Initial Performance date for the 60‐month periodic requirement
set forth in TPL‐007‐2 R4. As such, a plausible reading of the IP is that TPL‐007‐2 R4 does not become enforceable for 42 months and then,
when enforceable, entities have an additional 60 months to complete the Benchmark GMD study under TPL‐007‐2 R4’s periodic performance
requirement. This is consistent with NERC’s IP guidance in Compliance Application Notice (CAN) No. 12, which states: “[I]n the event the
Standard or interpretation is silent with regard to completing a periodic activity, CEAs are to verify that the registered entity has performed
the periodic activity within the Standard’s timeframe after the enforceable date.” (CAN 12 at 1‐2). Here, TPL‐007‐2 R4’s enforceable date is
set at 42 months from the effective date of the overall Standard. No initial performance date is specified. As such, a responsible entity may
reasonably conclude that it has the full 60 month window specified in TPL‐007‐2 R4 to complete the Benchmark GMD Vulnerability
Assessment. This result appears to run counter to the SDT’s intent. Texas RE therefore recommends the SDT clearly specify that the initial
performance of the TPL‐007‐2 R4 Benchmark GMD Vulnerability Assessment is due on the enforceable date of that requirement or 42 months
from the TPL‐007‐2 effective date. The same logic can be applied to Requirement R8 as well.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Brandon McCormick ‐ Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 5, 6, 4, 3; David Schumann, Florida
Municipal Power Agency, 5, 6, 4, 3; Ginny Beigel, City of Vero Beach, 3; Jeffrey Partington, Keys Energy Services, 4; Joe McKinney, Florida
Municipal Power Agency, 5, 6, 4, 3; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power Agency,
5, 6, 4, 3; Tom Reedy, Florida Municipal Power Pool, 6; ‐ Brandon McCormick, Group Name FMPA
Answer
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Question 7
Document Name
Comment
We would ask that the implementation plan for TPL‐007‐2 be clearer than it is, especially since the implementation plan for TPL‐007‐1 is
currently underway. We appreciate the efforts of the drafting team in developing the implementation plan for TPL‐007‐2. However, while it
may make perfect sense to the drafting team, it is not clear enough to be used for a compliance standard. Please consider providing some
examples, a timeline chart, or providing an acknowledgement of the current dates that entities will be working towards. For example, the
selection of the January 2021 date as the “dividing line” between “concurrent implementation” and apparently “non‐current”
implementation, of the Supplemental and Benchmark events seems to imply the SDT believes one year is sufficient time to add the
supplemental event to the benchmark Vulnerability Assessments that are already underway and required to be complete for TPL‐007‐1 by
January of 2022. However, the “more specific” dates offered for Requirements R3, R4 and R8 are 42 months out, which is not January of
2022…so what exactly is intended by “concurrent” and what benefit is gained?
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the Implementation Plan based on comments received. See the revised Implementation
Plan.
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
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Question 7
No comments were submitted.
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Consideration of Comments
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Question 8
8. Do you agree with the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for the requirements in proposed TPL‐007‐2? If
you do not agree, or if you agree but have comments or suggestions for the VRFs and VSLs provide your recommendation and explanation.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
They should be low or medium violation severity levels and risk factors at the most.
Likes 0
Dislikes 0
Response
Thank you for your comment. All VSLs16 and VRFs17 are consistent with NERC guidelines.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
They should be low or medium violaton severity levels and risk factors at the most.
Likes 0
Dislikes 0
Response
16 http://www.nerc.com/pa/Stand/Resources/Documents/VSL_Guidelines.PDF
17 http://www.nerc.com/pa/Stand/Resources/Documents/Violation_Risk_Factors.pdf
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Question 8
Thank you for your comment. All VSLs and VRFs are consistent with NERC guidelines.
18
19
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
Since the standard clearly identifies separate GMD Vulnerability Assessments for benchmark and supplemental GMD events, we believe an
entity could define separate acceptable System steady state voltage performance criteria for each study. Hence, the Violation Severity Limit
for Requirement R3 should be expanded with stair‐step severity limits that account for an entity having one criteria for one type of event and
not the other.
Likes 0
Dislikes 0
Response
Thank you for your comment. The VSL is binary because to address criteria as a single item.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
No
Document Name
Comment
Consistent with our comments above
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
18 http://www.nerc.com/pa/Stand/Resources/Documents/VSL_Guidelines.PDF
19 http://www.nerc.com/pa/Stand/Resources/Documents/Violation_Risk_Factors.pdf
Consideration of Comments
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Question 8
Response
Thank you for your comment. The SDT did not find Hydro One comments above pertaining to VRF or VSL.
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
No
Document Name
Comment
Duke Energy recommends that the drafting team revisit the order used for the Lower VSL for R8. The first statement in the Lower VSL section
regarding the responsible entity completing a supplemental GMD Vulnerability Assessment in more than 60 calendar months, should actually
swap positions with the second clause regarding the entity failing to satisfy one of the elements in R8. Having these two clauses swap places,
would align with the order of language used in the Moderate, High, and Severe VSL(s).
Likes 0
Dislikes 0
Response
Thank you for your comment The SDT has swapped the clauses in the Lower VSL to make it consistent with the Moderate, High, and Serve VSL
for Requirement R8.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
No
Document Name
Comment
As discussed above, AZPS has identified inconsistency in the treatment of a failure of registered entities to meet the deadline set forth for
certain administrative requirements. In some instances, the VSL is simply a binary element and does not increase based on duration of delay
or other factors. In other instances, the VSL increases as the duration of the delay increases. Such inconsistency alone is problematic, but,
when the administrative nature of and horizon within which these requirements occur are considered, it becomes clear that the VSLs are out
of sync with the actual or potential impact that would result from an entity’s failure to comply. As these are administrative requirements
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Question 8
(provision of documents and/or responses) occurring in the planning horizon, AZPS respectfully asserts that all such VSLs should be
considered “low” and should not increase beyond that level, which is similar to the treatment in Requirement R8. AZPS recommends that the
SDT review not only the new requirements, but the existing requirements to ensure that the VSLs accurately reflect their administrative
nature and the fact that the horizon within which these activities are occurring is the Planning Horizon. Specific requirements that should be
reviewed for consistency regarding the applicable VSLs include all requirement/sub‐requirements with a 90 day timeframe for compliance,
e.g., Requirements R4.3, R4.3.1, R5, R7.5, R7.5.1, R8.4, R8.4.1, and R9.2. Again, AZPS respectfully recommends that the SDT treat all 90‐day
time frame administrative requirements as binary requirements with a low VSL.
Likes 0
Dislikes 0
Response
Thank you for your comment. The gradation of the VSLs for Requirements with a timing component is consistent with the guideline for
developing VSLs.20 Regardless of whether a Requirement is administrative or not, a binary Requirement (i.e., met or not met) can only have a
single Severe category. Not performing the Requirement is the most serve violation of the Requirement.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
There should be trial period for industry to gain understanding and knowledge of GMD before implementing a standard.
Likes 0
Dislikes 0
Response
Thank you for your comment.
20 http://www.nerc.com/pa/Stand/Resources/Documents/VSL_Guidelines.PDF
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Question 8
Thomas Foltz ‐ AEP ‐ 5
Answer
No
Document Name
Comment
The VSL for R2 is based on the maintenance of a System Model that is already required by other reliability standards (MOD‐032). It is unclear
why this is a basis for the VSL for this requirement. The VSL for requirement R2 should pertain to the unique information required by the GIC
vulnerability assessments contained in this standard. AEP recommends having only one Severe VSL for not maintaining GIC model data.
Likes 0
Dislikes 0
Response
Thank you for your comment. The maintenance of models in MOD‐032 is different from the models used for GMD assessments. The SDT
proposed a High and Severe VSL to account for partial failure where only one model was maintained, but not both.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
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Question 8
Answer
Yes
Document Name
Comment
We suggest adding the following High VSL.
"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 and, performing
the study or studies needed to complete benchmark and supplemental GMD Vulnerability Assessment(s).),
Or
implementing process(es) to obtain GMD measurement data as specified in this standard."
Likes 0
Dislikes 0
Response
Thank you for your comment. The above suggestion does not provide additional clarity. The performance of Requirement R1 is to “identify
the individual and joint responsibilities” and the additional information outlines what individual and joint responsibilities are being identified
by the applicable entities.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
Yes
Document Name
Comment
We suggest adding the following High VSL.
"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 and, performing
the study or studies needed to complete benchmark and supplemental GMD Vulnerability Assessment(s),
Or
implementing process(es) to obtain GMD measurement data as specified in this standard."
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Question 8
Likes 0
Dislikes 0
Response
Thank you for your comment. The above suggestion does not provide additional clarity. The performance of Requirement R1 is to “identify
the individual and joint responsibilities” and the additional information outlines what individual and joint responsibilities are being identified
by the applicable entities.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
Yes
Document Name
Comment
The VRFs should be included in the VSL table within the standard. It isn’t clear why they were struck.
Likes 0
Dislikes 0
Response
Thank you for your comment. The Time Horizons and VRF items were removed from the Results‐based Standard (RBS) template to increase
the space for writing VSL language and to eliminate the potential for errors to be introduced when they do not match the Requirement(s).
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
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Question 8
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2, Group Name IRC Standards Review Committee
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Chris Scanlon ‐ Exelon ‐ 1
Consideration of Comments
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Question 8
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 8
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 8
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Consideration of Comments
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205
Question 8
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 8
Likes 0
Dislikes 0
Response
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
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
Consideration of Comments
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Question 8
Joshua Eason ‐ Joshua Eason On Behalf of: Michael Puscas, ISO New England, Inc., 2; ‐ Joshua Eason
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 8
Likes 0
Dislikes 0
Response
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
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209
Question 8
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Consideration of Comments
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210
Question 8
Comment
Likes 0
Dislikes 0
Response
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments
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211
Question 8
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Consideration of Comments
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Question 8
Document Name
Comment
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Consideration of Comments
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213
Question 8
Dislikes 0
Response
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Consideration of Comments
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214
Question 9
9. The SDT believes proposed TPL‐007‐2 provide entities with flexibility to meet the reliability objectives in the project Standards
Authorization Request (SAR) in a cost effective manner. Do you agree? If you do not agree, or if you agree but have suggestions for
improvement to enable additional cost effective approaches to meet the reliability objectives, please provide your recommendation and, if
appropriate, technical justification.
Thomas Foltz ‐ AEP ‐ 5
Answer
No
Document Name
Comment
While AEP agrees with the scope and direction of the revised standard, the incremental costs and resources required to comply with the
proposed revisions may not be commensurate with the resulting impact to the improved reliability of the BES. Adding the Supplemental GMD
Vulnerability obligations may substantially increase the resources involved, without a corresponding increase in the reliability of the BES.
Likes 0
Dislikes 0
Response
Thank you for your comment. The supplemental assessment is additional work, but it is necessary to account for the impacts of local
enhancements. No additional system data is required.
Michael Shaw ‐ Lower Colorado River Authority ‐ 6, Group Name LCRA Compliance
Answer
No
Document Name
Comment
This revision calls for even more assessment of an already rare condition that has historically not been very impactful at lower latitudes. I
question the cost‐benefit of this standard relative to other grid reliability needs.
Likes 0
Consideration of Comments
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215
Question 9
Dislikes 0
Response
Thank you for your comment. The SDT cannot comment on the priority of compliance with TPL‐007‐2 with respect to other needs that require
attention on the system.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
No
Document Name
Comment
There should be trial period for industry to gain understanding and knowledge of GMD before implementing a standard. Until initial
assessments are completed, there’s no idea of what a corrective action plan might look like, for example.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request. The existing standard already has a
vulnerability assessment requirement that is approved and effective and subject to compliance by applicable registered entities. The
comment is suggesting an alternative methodology to the existing standard which is outside the scope of the SDT and should be addressed in
a new SAR.
Chantal Mazza ‐ Hydro‐Québec TransEnergie ‐ 1,2 ‐ NPCC
Answer
No
Document Name
Comment
For the Hydro‐Quebec power grid it would be already covered by the benchmark event.
Likes 0
Consideration of Comments
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216
Question 9
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request.
Nicolas Turcotte ‐ Hydro‐Québec TransEnergie ‐ 1
Answer
No
Document Name
Comment
For the Hydro‐Quebec power grid it would be already covered by the benchmark event.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT is being responsive to the Standards Authorization Request.
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
No
Document Name
Comment
Cost effectiveness can’t be fully evaluated until more details are provided concerning how mitigation measures and GIC monitoring will be
handled. Any required hardware mitigation and GIC monitoring could potentially be costly.
Likes 0
Dislikes 0
Response
Consideration of Comments
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217
Question 9
Thank you for your comment. The SDT agrees that the cost cannot be evaluated until we have gone through a cycle of the implementation
plan.
Laurie Williams ‐ PNM Resources ‐ Public Service Company of New Mexico ‐ 1
Answer
No
Document Name
Comment
Requirement R12 placed responsible entities an additional cost responsibility to collect magnetometer data which would be used just for
model validation purpose. Collection of magnetometer data from government agencies or other appropriate agencies directly by NERC would
avoid responsible entities’ additional cost burden.
Likes 0
Dislikes 0
Response
Thank you for your comment. The standard allows for obtaining a data product from sources like the USGS or NRCan.
Larisa Loyfer The technical basis is not clear man ‐ CenterPoint Energy Houston Electric, LLC ‐ 1 ‐ Texas RE
Answer
No
Document Name
Comment
CenterPoint Energy disagrees that the proposed TPL‐007‐2 provides entities with flexibility to meet the reliability objectives in the project
Standards Authorization Request (SAR) in a cost effective manner. CenterPoint Energy’s disagreement is based on the following:
The proposed Implementation Plan for TPL‐007‐2 lacks the flexibility to complete the first‐of‐its‐kind modeling and analysis before
adding on additional enhanced analysis required to comply with Requirements R8 – R10.
The prescriptive implementation timelines required by revisions to Requirement R7 do not provide sufficient flexibility for entities to
weigh competing system reliability goals in a cost effective manner.
Consideration of Comments
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218
Question 9
Adding the Supplemental GMD Vulnerability obligations may substantially increase the resources involved, without a corresponding
increase in the reliability of the BES.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has proposed the phasing‐in of version 2 into the timing of the implementation of version 1, depending
on the timing of approval of the revised standard by FERC.
The supplemental assessment is additional work, but it is necessary to account for the impacts of local enhancements.
Payam Farahbakhsh ‐ Hydro One Networks, Inc. ‐ 1
Answer
No
Document Name
Comment
Consistent with our comments above
Likes 1
Hydro One Networks, Inc., 3, Malozewski Paul
Dislikes 0
Response
Donald Lock ‐ Talen Generation, LLC ‐ 5
Answer
No
Document Name
Comment
Consideration of Comments
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219
Question 9
TPL‐007‐2 continues the error of TPL‐007‐1 in allowing GOs to only suggest corrective actions (in R6.3), and giving the responsible entity in R7
sole authority to make establish CAPs without having to consult with GOs on the options available or (for competitive markets) demonstrate
that all competitors are treated equally. This could be a significant issue, in that CAPs may include directives for, “Installation, modification,
retirement or removal,” of multi‐million‐dollar equipment.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT expects that the development of the CAP would be a joint effort among the applicable entities.
Requirement 7.5.1 provides a feedback loop for those functional entities who are referenced in the CAP.
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
No
Document Name
Comment
OPG is of the opinion that the SDT can improve the cost effectiveness of the standard by combining the Benchmark and the Supplemental
GMD events under one definition, thus eliminating duplicate/unnecessary work.
Likes 0
Dislikes 0
Response
Thank you for your comment. The Transformer Thermal Impact Assessment White Paper and Screening Criterion for Transformer Thermal
Impact Assessment documents have provided the technical foundation and methodologies that can be used to conduct transformer
temperature rise calculations for both the benchmark case and the supplemental case.
Chris Scanlon ‐ Exelon ‐ 1
Answer
No
Consideration of Comments
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220
Question 9
Document Name
Comment
It is not clear whether the newly established supplemental event will have the effect of increasing the scope of transformers that meet the
screening criteria, when compared to the benchmark event and if so, by how much. It does seem possible that an entity which has had no
transformers identified as meeting the benchmark event screening criteria could have multiple or all transformers included within the scope
of the supplemental event if it is located within the area of a localized enhancement. The technical justification for the supplemental event
screening criteria does not substantiate what appears to be a disproportional increase in the intensity of the event compared to the increase
in the screening threshold from 75A to 85A. Note that the approach to the thermal assessments required under R6 and R10 are the same,
and therefore the proposed supplemental event screening criteria has the ability to impact the financial obligation of the TO and GO.
Likes 0
Dislikes 0
Response
Thank you for your comment. Different screening thresholds were selected because benchmark and supplemental benchmark waveforms are
different and their effects on transformers are different. The temperature thresholds are consistent, i.e., the thermal effects on a
transformer are characterized by peak temperatures.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits.
Likes 0
Dislikes 0
Response
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
221
Question 9
Thank you for your comment. In the development of the TPL‐007‐2: Transmission System Planned Performance for Geomagnetic Disturbance
Events standard with supplemental GMD event, the SDT is being responsive to the Standards Authorization Request. The consensus of the
SDT is that the supplemental GMD Vulnerability Assessment provides a reliability benefit.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
No
Document Name
Comment
Increased costs do not justify the low, if any, reliability benefits.
Likes 0
Dislikes 0
Response
Thank you for your comment. In the development of the TPL‐007‐2: Transmission System Planned Performance for Geomagnetic Disturbance
Events standard with supplemental GMD event, the SDT is being responsive to the Standards Authorization Request. The consensus of the
SDT is that the supplemental GMD Vulnerability Assessment provides a reliability benefit.
William Harris ‐ Foundation for Resilient Societies ‐ 8
Answer
No
Document Name
Foundation for Resilient Societies on NERC Project 2013 081117_Submitted.docx
Comment
The only cost‐effective approach for grid protecton is to design for severe GMD hazards and manmade EMP hazards concurrently. This is not a
cost effective method, and results in a needlessly vulnerable electric grid. See general comments.
Likes 0
Dislikes 0
Response
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Question 9
Thank you for your comment. Protection of the BES for EMP hazards is outside the scope of the SDT.
sean erickson ‐ Western Area Power Administration ‐ 1
Answer
Yes
Document Name
Comment
TPLTF21 Discussion: The group agrees that the SDT has done a good job of considering cost in time, resources, and personnel commitment in
meeting the objectives of the SAR, which were heavily prescribed by FERC Order No. 830. The group may not agree with the perceived
benefit to reliability that the additional effort to analyze the supplemental GMD event will yield, but the SDT has proposed a solid means of
addressing the FERC directives without relying on tools or methods that do not exist widely in industry today. The group also supports the
SDT cost‐effective approach to the proposed Requirement R7 which does not mention GIC blocking devices as an integral part of a hardware
mitigation. The group remains concerned with the perception that GIC mitigation hardware is presently a viable solution. Given its cost,
effects on Protection System design, as well as potential compromises to existing BES reliability, GIC blocking devices may prove
undesirable. The flexibility that the SDT has proposed in the development of Corrective Action Plans is workable.
Likes 0
Dislikes 0
Response
The SDT appreciates the supportive comment.
Stephanie Burns ‐ Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; ‐
Stephanie Burns
Answer
Yes
Document Name
Comment
21 TPLTF document is found at the end of this document in Attachment 1.
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Question 9
Considering the additional supplemental GMD event analysis doesn’t require a CAP to be developed and that data collection is allowed as
opposed to having to install new monitoring equipment on the system to acquire the required data, the proposed revisions are flexible and
potentially more cost effective for some entities.
Likes 0
Dislikes 0
Response
The SDT appreciates the supportive comment.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group agrees that the SDT has done a good job of considering cost in time, resources, and personnel commitment
in meeting the objectives of the SAR, which were heavily prescribed by FERC Order No. 830. The group may not agree with the perceived
benefit to reliability that the additional effort to analyze the supplemental GMD event will yield, but the SDT has proposed a solid means of
addressing the FERC directives without relying on tools or methods that do not exist widely in industry today. We also support the SDT cost‐
effective approach to the proposed Requirement R7 which does not mention GIC blocking devices as an integral part of a hardware
mitigation. The group remains concerned with the perception that GIC mitigation hardware is presently a viable solution. Given its cost,
effects on Protection System design, as well as potential compromises to existing BES reliability, GIC blocking devices may prove
undesirable. The flexibility that the SDT has proposed in the development of Corrective Action Plans is workable.
Likes 0
Dislikes 0
Response
The SDT appreciates the supportive comment.
Randy Buswell ‐ VELCO ‐Vermont Electric Power Company, Inc. ‐ 1
Consideration of Comments
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Question 9
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Lauren Price ‐ American Transmission Company, LLC ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
RoLynda Shumpert ‐ SCANA ‐ South Carolina Electric and Gas Co. ‐ 1,3,5,6 ‐ SERC
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 9
Likes 0
Dislikes 0
Response
Ann Ivanc ‐ FirstEnergy ‐ FirstEnergy Solutions ‐ 6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 9
Robert Blackney ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Gerry Huitt ‐ Xcel Energy, Inc. ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 9
Likes 0
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments
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228
Question 9
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
Jeffrey Watkins ‐ Jeffrey Watkins On Behalf of: Eric Schwarzrock, Berkshire Hathaway ‐ NV Energy, 5; ‐ Jeffrey Watkins
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Consideration of Comments
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Question 9
Comment
Likes 0
Dislikes 0
Response
Douglas Webb ‐ Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; Harold Wyble,
Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; James McBee, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6,
5, 1; Jessica Tucker, Great Plains Energy ‐ Kansas City Power and Light Co., 3, 6, 5, 1; ‐ Douglas Webb
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Quintin Lee ‐ Eversource Energy ‐ 1
Answer
Yes
Document Name
Comment
Consideration of Comments
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230
Question 9
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 Hydro One, HQ and IESO
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Question 9
James Anderson ‐ CMS Energy ‐ Consumers Energy Company ‐ 1,3,4,5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michael Buyce ‐ City Utilities of Springfield, Missouri ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
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Question 9
Likes 0
Dislikes 0
Response
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
Texas RE does not have comments on this questions.
Likes 0
Dislikes 0
Response
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233
Question 9
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
Richard Vine ‐ California ISO ‐ 2
Answer
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Consideration of Comments
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234
Question 10
10. Provide any additional comments for the SDT to consider, if desired.
Terry Harbour ‐ Berkshire Hathaway Energy ‐ MidAmerican Energy Co. ‐ 1
Answer
Document Name
Comment
The approved TPL‐007‐1 and the current draft of TPL‐007‐2 includes a flowchart diagram in the Application Guides section that provides and
overall view of the GMD Vulnerability Assessment process (and the requirements in TPL‐007). There has been confusion as to which
requirements are represented in the diagram. The NSRF suggest the SDT update this diagram to include annotations that identify the
requirements in TPL‐007‐2. Please see the NSRF example which includes requirements for the benchmark and supplemental assessment.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT did not add references to the flowchart in the Application Guidelines as the flowchart is not a one‐to‐
one relationship with the standard requirements.
Dennis Sismaet ‐ Northern California Power Agency ‐ 6
Answer
Document Name
Comment
None. Thank you.
Likes 0
Dislikes 0
Response
Consideration of Comments
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235
Question 10
Sergio Banuelos ‐ Tri‐State G and T Association, Inc. ‐ 1,3,5 ‐ MRO,WECC
Answer
Document Name
Comment
Tri‐State would like for some additional guidance or examples on what the SDT meant by "hardware" and "non‐hardware".
Likes 0
Dislikes 0
Response
Thank you for your comment. The standard is not prescriptive in listing the various hardware and non‐hardware options. Some hardware and
non‐hardware options are listed in Requirement R7.1.
Marty Hostler ‐ Northern California Power Agency ‐ 5
Answer
Document Name
Comment
No additional comments.
Likes 0
Dislikes 0
Response
Richard Vine ‐ California ISO ‐ 2
Answer
Consideration of Comments
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236
Question 10
Document Name
Comment
The California ISO supports the joint comments of the ISO/RTO Standards Review Committee
Likes 0
Dislikes 0
Response
Thank you for supporting the comments of the IRC Standards Review Committee (i.e., ISO/RTO Standards Review Committee).
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
1. Add a comma after the “Table 1” reference within Requirement R7, as the lengthy description within the requirement describes the
responsible entity and not the development of a CAP.
2. The evidence retention period demonstrating the implementation of a process to obtain GIC monitor and geomagnetic field data, as
listed within R11 and R12, is identified as three calendar years. We do not see how this should be different than the evidence
retention period identified for the requirements of NERC Reliability Standard TPL‐001‐4, which is based on the last compliance audit.
3. We thank you for this opportunity to provide these comments.
Likes 0
Dislikes 0
Response
Thank you for your comment.
1.
The SDT added a comma after “Table 1” in Requirement R7.
2.
The evidence retention period meets the NERC Guidelines.
Consideration of Comments
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237
Question 10
Scott Downey ‐ Peak Reliability ‐ 1
Answer
Document Name
Comment
While Peak supports the SDTs effort, we believe that consideration should be given to making TOPs applicable to the standard as well.
Applicable TOPs are required to have operating plans for GMDs to comply with EOP‐010 but without direct evaluation of TPL‐007 vulnerability
assessments, the plans would seem to be incomplete. Peak recognizes the requirement for proposed applicable functions to provide their
vulnerability assessments to the RC but believes a more direct coordination role with the TOP should be required.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT does not agree with the suggestion to make TOPs applicable entities in the standard. TPL‐007 is a
planning standard and applies to registered planning entities and selected asset owners. The comment is suggesting an alternative
methodology to the existing standard which is outside the scope of the SDT and should be addressed in a new SAR.
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Hydro One, HQ and IESO
Answer
Document Name
Comment
On page 11 Table 1 – Note 3 should be also applicable to the row entitled “Supplemental GMD Event – GMD Event with Outages” as it relates
to columns “Interruption of Firm Transmission Service Allowed” and “Load Loss Allowed”.
Likes 0
Dislikes 0
Response
Consideration of Comments
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238
Question 10
Thank you for your comment. The SDT asserts that because a CAP is not required, the additional footnote is not applicable.
Thomas Rafferty ‐ Edison International ‐ Southern California Edison Company ‐ 5
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes 0
Dislikes 0
Response
No comments were submitted.
David Ramkalawan ‐ Ontario Power Generation Inc. ‐ 5
Answer
Document Name
Comment
OPG does not agree with the implementation deadlines:
1) The four years deadline to implement all the hardware mitigation action may provide unfair market advantage to the unaffected/ less
affected TOP, GOP due to the time/resources/financial effort involved. Continued operation should be allowed if there is a shortage of
hardware, or the lead time to design/procure/implement complete hardware solution exceeds the four years duration.
2) TPL‐007‐2 should also be applicable as a Functional Entity to Generator Operator (GOP). The implementation of hardware mitigating
actions may require the revision of the existing approved GIC mitigation operating procedure instructions (same if the non‐hardware
mitigation requires operating procedures revisions). The commissioning of the mitigating actions will also require coordination’s between the
TOP and GOP. GOP should be a stakeholder regarding the configuration impact and determination of affected transformers. Additionally
alternative operating configuration may requires design studies involving/requiring GOP support before implementation.
Consideration of Comments
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Question 10
3) The two years deadline to implement all the non‐hardware solution may provide unfair market advantage to the unaffected/less
affected TOP, GOP, as the implementation for a large scale TOP, GOP will take more time, resources/financial effort and may require
commissioning and studies.
Likes 0
Dislikes 0
Response
Thank you for your comment.
1. It is anticipated that the actual implementation (trigger to activate) of the CAP that includes operational procedure would only occur
during a GMD/GIC event of sufficient size as determined by the assessment. Since GMD events are very rare, there is less likelihood
that market impacts would occur as compared to a ‘regular’ transmission outage or constraint not related to GMD mitigation.
2. The GOPs may be involved with the execution of the CAP, as suggested in the comment, but that does not mean that the GOP should
be an applicable entity in the standard.
3. See response to 1 above.
Pamela Hunter ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1,3,5,6 ‐ SERC, Group Name Southern Company
Answer
Document Name
Comment
Table 1 in the standard, under the “Steady State:” heading, part a, the sentence should be expanded as follows: “Voltage collapse, Cascading,
and uncontrolled islanding shall not occur for the Benchmark GMD event, but can occur for the Supplemental GMD event subject to
additional analysis specified in R8.3.
Also, verbiage in R8.3 should be expanded to include references to Voltage collapse and uncontrolled islanding
Likes 0
Dislikes 0
Response
Consideration of Comments
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Question 10
Thank you for your comment. The SDT does not agree with the suggestion. Voltage collapse, Cascading, and uncontrolled is not allowed in
either the benchmark or supplemental assessments. The distinction in R8.3 is that a CAP is not required in the case of the supplemental
assessment.
Colby Bellville ‐ Colby Bellville On Behalf of: Dale Goodwine, Duke Energy , 6, 5, 3, 1; ‐ Colby Bellville, Group Name Duke Energy
Answer
Document Name
Comment
Duke Energy requests further clarification regarding the 90 calendar day timeframe outlined in R4. The current language states that the
Responsible Entity must provide its benchmark GMD Vulnerability Assessment to the RC, adjacent PC, and adjacent TP within 90 calendar
days of completion. Clarification is needed as to what date the term “completion” is referring to. Many entities may have 3rd parties conduct
these studies, and in doing so, the Responsible Entity will review the study and make corrections where necessary. Is the completion date
referred to in the requirement referring to the date the initial study (by the 3rd party) is completed, or is it referring to the date that the
Responsible Entity has completed its internal review and obtained signoff by management? If the drafting team’s intent was for the
completion date to refer to the date that the initial study was performed, we cannot agree with the 90 calendar day timeframe. Additional
time would be needed for the Responsible Entity to perform its review of the 3rd party study, and obtain management signoff.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT believes that the completion date is the date when the Responsible Entity considers it complete; that
is, it has completed all internal reviews and management approvals.
Eric Shaw ‐ Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; ‐ Eric Shaw
Answer
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
241
Question 10
None
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
Although not necessarily in the scope of this project, Texas RE noticed a few other things.
There could be some clarity in which earth models are supposed to be used. The “earth model” physiographic regional maps supplied
and referenced are not detailed enough to indicate the physical locations of the regional conductivity map boundaries. This lack of
detail will be a source of confusion if a transformer is located near a conductivity boundary. What earth model value does the
responsible entity use? If there are 3 regional conductivity areas in one responsible entity’s planning area, what earth model value
does the responsible entity use?
Texas RE is concerned the lack of a timeframe to provide GIC flow information in Requirements R5 and R9 could lead to an entity not
providing GIC flow information when that information is necessary for the thermal impact assessments. Texas RE requests the SDT add
a timeframe for providing the data.
Although R1 states the PCs and TPs will identify the individual and joint responsibilities for maintaining models and performing the
studies needed to complete the benchmark and supplemental GMD Vulnerability Assessments, there does not appear to be any
coordination while actually performing these tasks. Texas RE is concerned this could lead to TPs each doing their own studies and
coming to different conclusions, which would not allow entities to recognize vulnerabilities effectively. Texas RE recommends the PC
do an overall assessment every 60 calendar months.
Likes 0
Consideration of Comments
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Question 10
Dislikes 0
Response
Thank you for your comment. The NERC GMD Task Force whitepaper, GIC Application Guide, published December 2013,
(http://www.nerc.com/comm/PC/Pages/Geomagnetic‐Disturbance‐Task‐Force‐(GMDTF)‐2013.aspx) discusses the use of available earth
conductivity models in performing the required calculations.
The SDT is reluctant to set deadlines for the issuance of GIC calculations because the level of effort will vary widely in the various systems in
North America. As an alternative, significant time has been allowed in the implementation plan to do the assessments required by R6 and
R10.
The purpose of R1 is to ensure that the roles and responsibilities are clear to all, including how the PC will fit the pieces together if there are a
number of entities contributing to an overall assessment.
Kenya Streeter ‐ Edison International ‐ Southern California Edison Company ‐ 6
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison.
Likes 0
Dislikes 0
Response
No comments were submitted.
Karie Barczak ‐ DTE Energy ‐ Detroit Edison Company ‐ 3
Answer
Document Name
Comment
Consideration of Comments
2013‐03 Geomagnetic Disturbance Mitigation | October 2017
243
Question 10
no
Likes 0
Dislikes 0
Response
Dana Klem ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Document Name
Comment
The approved TPL‐007‐1 and the current draft of TPL‐007‐2 includes a flowchart diagram in the Application Guides section that provides and
overall view of the GMD Vulnerability Assessment process (and the requirements in TPL‐007). There has been confusion as to which
requirements are represented in the diagram. The NSRF suggest the SDT update this diagram to include annotations that identify the
requirements in TPL‐007‐2. Please see example below which includes requirements for the benchmark and supplemental assessment.
Likes 1
Darnez Gresham, N/A, Gresham Darnez
Dislikes 0
Response
Thank you for your comment. The SDT did not add references to the flowchart in the Application Guidelines as the flowchart is not a one‐to‐
one relationship with the standard requirements.
Sandra Shaffer ‐ Berkshire Hathaway ‐ PacifiCorp ‐ 6
Answer
Document Name
Comment
Consideration of Comments
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244
Question 10
“PacifiCorp requests the drafting team add to the white paper links to the resources where geomagnetic field data from the
magnetometers inside NERC footprint is publicly available.”
Likes 0
Dislikes 0
Response
Thank you for your comment. The government entity magnetometer station data is available at: US‐‐ https://geomag.usgs.gov/; Canada‐‐
http://geomag.nrcan.gc.ca/lab/default‐en.php. The SDT will add those links to the whitepaper as the comment suggests.
Romel Aquino ‐ Edison International ‐ Southern California Edison Company ‐ 3
Answer
Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison.
Likes 0
Dislikes 0
Response
No comments were submitted.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
Document Name
Comment
AZPS is concerned that the proposed revisions to Requirement R1 to add references to the need for processes related to obtaining GMD data
is inconsistent with respect to how such data is defined in later requirements, e.g., Requirements R11 and R12, and creates confusion relative
Consideration of Comments
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245
Question 10
to the need and use of such data and to which data‐related actions and requirements Requirement R1 applies. For these reasons, AZPS
proposes the following revisions to ensure clarity:
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, including the data‐
related processes identified in Requirements R9, R11, and R12 in this standard, and, performing the study or studies needed to complete
benchmark and supplemental GMD Vulnerability Assessments. [Violation Risk Factor: Lower] [Time Horizon: Long‐term Planning]
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT has revised the blue rationale box for Requirements R11 and R12 to raise awareness of the differences
in the data.
Mike Smith ‐ Manitoba Hydro ‐ 1, Group Name Manitoba Hydro
Answer
Document Name
Comment
The standard doesn’t talk about how to develop equivalents of neighbouring systems and what assumptions to make. Is there only a GMD
event impacting your assessment area and none in neighbouring areas?
Likes 0
Dislikes 0
Response
Thank you for your comment. Guidance on modeling is contained in the following guides published by the NERC GMD Task Force: GIC
Application Guide, September 2013 and GMD Planning Guide, December 2013 (see: http://www.nerc.com/comm/PC/Pages/Geomagnetic‐
Disturbance‐Task‐Force‐(GMDTF)‐2013.aspx)
Daniel Grinkevich ‐ Con Ed ‐ Consolidated Edison Co. of New York ‐ 1
Consideration of Comments
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Question 10
Answer
Document Name
Comment
On page 11 Table 1 – Note 3 should be also applicable to the row entitled “Supplemental GMD Event – GMD Event with Outages” as it relates
to columns “Interruption of Firm Transmission Service Allowed” and “Load Loss Allowed”.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT asserts that because a CAP is not required, the additional footnote is not applicable.
Thomas Foltz ‐ AEP ‐ 5
Answer
Document Name
Comment
The language used for Measure M5 was adjusted incorrectly as it currently states “… that it has provided the maximum effective benchmark
GIC value to the Transmission Owner and Generator….. “. This is an incorrect statement and should instead state “...that it has provided the
maximum effective GIC value under the benchmark event to the Transmission Owner and Generator…..”
While AEP supports the overall effort of the drafting team, AEP has chosen to vote "no" driven by the lack of clarity related to the potential
duplication of efforts related to assets which are in‐scope for both the benchmark and supplemental assessments. Similarly, AEP is concerned
by the overall burden associated with having a secondary suite of “parallel requirements” to accommodate the supplemental assessment.
Likes 0
Dislikes 0
Response
Consideration of Comments
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Question 10
Thank you for your comment. The SDT removed “benchmark” in Measure M5 and a conforming change by removing “supplemental” in
Measure M9. The SDT purposely is requesting two separate thermal assessments be done for transformers that exceed the GIC thresholds:
One for the benchmark event and one for the supplemental event. The supplemental assessment is intended to address local enhancements.
The benchmark assessment may result in a Corrective Action Plan, but the supplemental assessment does not.
Kristine Ward ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5,6 ‐ FRCC
Answer
Document Name
Comment
Comments:
1. Parallels between R4 and R8:
It appears that the standard is now requiring applicable entities to perform two GMD Vulnerability assessments (benchmark and
supplemental), either at the same time, or within 5 years or less of each other. This seems to be duplicative and should be characterized as a
sensitivity to the benchmark and done at the same time if required or be performed as part of “subsequent” assessments. Also on that note,
the supplemental assessment has an additional requirement (R8.3) to determine if Cascading occurs, where the benchmark assessment does
not. Cascading is often required to be determined via stability analysis which is outside the scope of TPL‐007‐2 because the standard as
written only requires steady state/load flow analysis. Can the SDT please elaborate on this shift in requiring entities to evaluate Cascading in
the supplemental assessment and not in the benchmark assessment, as well as elaborate on the need to evaluate Cascading as a whole?
Also, the requirement of having to provide the completed assessment to the applicable entities, rather than just making it available (as
originally drafted), is not providing any reliability benefit other than paperwork for the entities, I thought Paragraph 81 was initiated to get
away from such requirements and here we are putting them right back in.
1. R7.3.1,7.3.2:
What does the SDT envision as a “non‐hardware” mitigation vs. a hardware mitigation?
1. R4, R8
Why does the SDT feel it necessary to add the phrase “at least” in the requirements associated with subsequent GMD assessments? The
existing language, without the insert, does not preclude an entity from performing an assessment sooner than the 60 calendar months if the
entity determines it necessary, the insert of “at least” provides no added benefit or clarity to the existing language.
1. Applicable Facilities:
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Question 10
Has the SDT given any consideration to clarifying the applicable Facilities within TPL‐007‐2? The standard is only applicable to PCs, TOs, and
GOs; however, there are transformers that are wye‐grounded on the high‐voltage terminals, operated at greater than 200 kV but are not
owned by registered TOs or have been excluded from the BES, pursuant the BES Definition. How does the SDT plan to address those? For
example, a GO can provide their respective PC with GSU information for the GMD model; however, their auxiliary transformer(s) which are
connected on the high‐side at 200 kV or greater and are wye‐grounded are not considered BES Facilities and therefore are not required to be
provided to the PC as part of their evaluation, even though the unit auxiliary transformers have the potential of tripping the entire plant.
1. Cost Study
Seminole requests the SDT perform a CEAP (Cost Effective Analysis Process) for this Standard. TPL‐007 is a great candidate as the costs of
all of the studies is substantial and the frequency of an event causing catastrophic consequences is low.
2. FRCC Specific TPL‐007‐2
Seminole requests that the SDT develop an initial low cost study that would allow for entities in the very far south to be excluded from
performing further compliance measures. In the alternative, Seminole requests the SDT to note that the SDT is open to the idea of
reduced requirement FRCC‐specific TPL‐007‐2.
1. 7.3.1
Change the time value to 24 months instead of 2 years to stay consistent. Same with 7.3.2.
1. R11 Note
The Note for R11 states that the data collected via magnetometers and GIC monitoring is necessary for “situational awareness”. Does the SDT
believe that the data collected for situational awareness could classify this collection equipment as BES Cyber Assets if system operators make
decisions based off of this equipment within 15 minutes?
Likes 0
Dislikes 0
Response
Thank you for your comment. The revised standard is requiring a second (supplemental) assessment to be performed coincident with the
original (benchmark) assessment to explicitly account for the impacts associated with local enhancements. Since the SDT is not requiring a
CAP for the supplemental assessment, it can be thought of as a sensitivity to the benchmark assessment. Cascading is not allowed in either
assessment and to the degree that there is inconsistency in the wording, the SDT will make corrections. The assessments are steady state and
not intended to imply dynamics analysis.
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Question 10
The reliability benefit comes from performing a GMD vulnerability assessment using an enhanced GMD event.
Examples of hardware mitigation include equipment replacement or modification, GIC blocking devices, protection systems, etc. Examples of
non‐hardware mitigation include operating procedures, etc.
The SDT did not remove the phrase “at least” as suggested.
The intent of the standard is to protect the BES and therefore, the SDT does not intend to address non‐BES facilities in the standard. Planning
entities can choose to address other facilities in their assessments if they conclude that those facilities can have a meaningful impact to the
results.
The SDT believes that it has addressed the concerns of the low latitude entities through the use of geomagnetic latitude scaling, which does
not exempt entities from the requirements of performing the analyses. The state of the scientific knowledge on GMD is such that a blanket
exemption from performing the analyses below certain latitudes is not prudent.
The SDT does not agree with the change from “two years” to “24 months” in 7.3.1 and 7.3.2 as suggested.
The statement in the information box associated with R11 comes from the FERC Order No. 830. It is included for information and not
intended to imply any requirements in this standard. Situational awareness is a term used in operations and not applicable here.
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Resilient Societies
Comments of the Foundation for Resilient Societies on NERC Project 2013‐03 Geomagnetic Disturbance Mitigation, Transmission
System Planned Performance for Geomagnetic Disturbance Events, Draft of TPL‐007‐2.
We provide brief comments on the Draft Standard, Draft Implementation Plan, and Research Work Plan of NERC.
Draft Reliability Standard TPL‐007‐2 is based on modeling that is substantially divorced from the empirical evidence of bulk power
system equipment susceptibility to damage or total losses during moderate geomagnetic disturbances during just the past three
decades.
NERC’s GMD Vulnerability Assessment process lacks scientific rigor. A rigorous standard would include:
Collection of all known or likely bulk power system equipment damage or loss during all three known classes of geomagnetic
disturbance: (1) coronal mass ejections (CMEs) , upon which NERC has concentrated; (2) more extended duration but less
intense coronal hole proton streams (CHs), associated with a substantially larger set of EHV transformer fires and explosions
during the past three decades; and (3) sudden commencement or sudden reversal GMDs¸ such as occurred at Seabrook
Station between November 8 and 10, 1998, with resulting meltdown of lower voltage windings in the Phase A 345 kV
transformer.
Transformer thermal impact assessments, if performed only if the maximum effective geomagnetically induced current (GIC) in the
transformer is equal or greater than 75 amps per phase for the benchmark GMD event, and 85 amps per phase for the supplemental
GMD event, are imprudent and needlessly risky, for a class of equipment with replacement times measured in months or years.
Idaho National Laboratory suspended injection of quasi‐DC currents into a 138 kV transformer during tests with and without
attachment of a neutral ground blocker in year 2013. Why was it necessary for INL test managers to suspend the DC current
injections at a level of 22 amps per phase, to avert transmission system damage, if the standard’s threshold is “prudently” set at 75
amps per phase?
What is needed is a more comprehensive set of GMD classes of hazard, a sharing of data on equipment losses since at least year
1989, not year 2013, improved modeling, and widespread testing of vulnerable BES equipment both under load and to destruction.
Geomagnetically Induced Current (GIC) data should be retained indefinitely, not for the 3 years specified in the draft standard,
because the return period for severe solar storms can be in excess of 100 years.
NERC claims that “the respective screening criteria are conservative…” (NERC Thermal Screening Criterion White Paper, 2017). We
dispute this claim and see no scientific foundation for it. As a result of these deficiencies, the bulk electric system remains highly
vulnerable to natural occurring geomagnetic disturbances, and more powerful high altitude electromagnetic pulse (EMP) hazards
that are manmade.
Respectfully submitted by:
William R. Harris
SDT Response:
TPL‐007 requires two distinct types of assessment. The first one is a system assessment which is determined by the largest
geoelectric field estimated to occur once in 100 years. This assessment evaluates effects such as reactive power loss, voltage
depression and harmonics due to the interaction of a dc (peak) geoelectric field with the power system. The second
assessment looks at the thermal effects of time‐varying GIC(t) on transformers. The GIC(t) waveform depends on the static
GIC distribution obtained from the system assessment. The 75 A/phase and 85 A/phase screening thresholds are calculated
using the benchmark and supplemental benchmark waveforms, respectively. Comparing the screening current thresholds
with the constant dc injected in in the INL tests is inappropriate and incorrect.
The INL tests did not monitor transformer hot spots, therefore the SDT cannot comment on conjectures regarding testing
parameters used.
The NERC 1600 Data Request will address the data retention of the GIC monitor data and geomagnetic field data collected by
NERC. The 3‐year retention period relates to the time frame that an applicable entity must retain evidence of their processes
for compliance with Requirements R11 and R12.
The SDT has used 20 years of consistent geomagnetic field measurements to estimate 1 in 100 year benchmark events
regardless of the physical processes captured by the measurements.
The SDT agrees with the need to improve modelling and testing, which will be addressed with NERC`s research plan.
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Comments from Avangrid
1. The SDT developed proposed Requirements R8 – R10 and the supplemental GMD event to address FERC concerns with the
benchmark GMD event used in GMD Vulnerability Assessments. (Order No. 830 P.44, P.47‐49, P.65). The requirements will obligate
responsible entities to perform a supplemental GMD Vulnerability Assessment based on the supplemental GMD event that accounts
for potential impacts of localized peak geoelectric fields. Do you agree with the proposed requirements? If you do not agree, or if
you agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
Yes
No
Comments:
2. The SDT developed the Supplemental GMD Event Description white paper to provide technical justification for the supplemental
GMD event. The purpose of the supplemental GMD event description is to provide a defined event for assessing system
performance for a GMD event which includes a local enhancement of the geomagnetic field. Do you agree with the proposed
supplemental GMD event and the description in the white paper? If you do not agree, or if you agree but have comments or
suggestions for the supplemental GMD event and the description in the white paper provide your recommendation and explanation.
Yes
No
Comments:
3. The SDT established an 85 A per phase screening criterion for determining which power transformers are required to be assessed
for thermal impacts from a supplemental GMD event in Requirement R10. Justification for this threshold is provided in the revised
Screening Criterion for Transformer Thermal Impact Assessment white paper. Do you agree with the proposed 85 A per phase
screening criterion and the technical justification for this criterion that has been added to the white paper? If you do not agree, or if
you agree but have comments or suggestions for the screening criterion and revisions to the white paper provide your
recommendation and explanation.
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Yes
No
Comments: “Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event” from the screening criterion
document provides a useful visual, can the drafting team additionally provide a similar chart and the data for the supplemental GMD
event?
SDT Response:
Thank you for your comment. Figure 2 in the Screening Criteria document is only an illustrative example of a GIC(t) waveform
and thermal response time series would look like for the particular level of GIC and event.
The SDT agrees that accuracy of models and tools is very important and that their improvement and validation are the main drivers
for the research plan. The upper bound of hot spot temperatures are provided in Figure 3 of the Screening Criterion for Transformer
Thermal Impact Assessment white paper and in Tables 1 and 2 of Appendix 1 of the same document.
4. The SDT revised the Transformer Thermal Impact Assessment white paper to include the supplemental GMD event. Do you agree
with the revisions to the white paper? If you do not agree, or if you agree but have comments or suggestions on the revisions to the
white paper provide your recommendation and explanation.
Yes
No
Comments: Table 1 and 2 are useful to show the differences between the benchmark event and the supplemental, but some of the
figures are not clear which GMD event was used to generate the gic(t) time series. Can some additional language be added to clarify
the GMD event of the figures in this document?
Also, there was some inconsistency in axis labels and units between the various figures, which makes it difficult to draw conclusions
when comparing the charts. For example A/phase versus Amps, minutes versus hours for the time scale. Can these charts be
updated with uniform axis labels and units for comparative purposes?
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SDT Response:
Thank you for your comment. This version of the white paper is intended to illustrate different ways to carry out thermal
transformer assessments. The time series used in the white paper are based on portions of the benchmark time series and
are intended for illustrative purposes only. The Figures in the white papers are sufficiently clear for their intended use.
5. The SDT developed proposed Requirement R7 to address FERC directives in Order No. 830 for establishing Corrective Action Plan
(CAP) deadlines associated with GMD Vulnerability Assessments (P. 101, 102). Do you agree with the proposed requirement? If you
do not agree, or if you agree but have comments or suggestions for the proposed requirement provide your recommendation and
explanation.
Yes
No
Comments:
6. The SDT developed Requirements R11 and R12 to address FERC directives in Order No. 830 for requiring responsible entities to
collect GIC monitoring and magnetometer data (P. 88; P. 90‐92). Do you agree with the proposed requirements? If you do not agree,
or if you agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
Yes
No
Comments: Neutral current measurements are not sufficient to benchmark autotransformer performance in a GMD event; TOs
would need at least two out of three leg measurements to do this. Additionally, the proxy magnetometer data leaves flexibility for
the TO, but may not prove to be effective for benchmarking without other additional considerations. While the intent of the R11
requirement is to benchmark the model, without accurate magnetometer installations in each TOs footprint, it may be difficult to do
so; particularly where no nearby proxy data can be leveraged. Can the drafting team consider increasing R11 further and require TOs
to either install measuring devices in their area, and/or to prove the accuracy of the proxy data? Also, can the drafting team consider
a requirement for additional measurements on autotransformers?
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SDT Response:
Thank you for your comment. Requirement R11 addresses the process for data collection. The standard does not address the
appropriateness of magnetometer site installation and validity of data.
7. Do you agree with the proposed Implementation Plan for TPL‐007‐2? If you do not agree, or if you agree but have comments or
suggestions for the Implementation Plan provide your recommendation and explanation.
Yes
No
Comments:
8. Do you agree with the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for the requirements in proposed TPL‐
007‐2? If you do not agree, or if you agree but have comments or suggestions for the VRFs and VSLs provide your recommendation
and explanation.
Yes
No
Comments:
9. The SDT believes proposed TPL‐007‐2 provide entities with flexibility to meet the reliability objectives in the project Standards
Authorization Request (SAR) in a cost effective manner. Do you agree? If you do not agree, or if you agree but have suggestions for
improvement to enable additional cost effective approaches to meet the reliability objectives, please provide your recommendation
and, if appropriate, technical justification.
Yes
No
Comments:
10. Provide any additional comments for the SDT to consider, if desired.
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Comments:
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Attachment 1
SPP TPLTF Review of TPL‐007‐2 Comment Questions published by Project 2013‐03 (Geomagnetic Disturbance Mitigation)
In July 2017, the Project 2013‐03 Standard Drafting Team (SDT) released an unofficial comment form to allow the industry to provide
feedback on the proposed TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events standard. It
is noted that the industry comment period is brief and all comments must be submitted by Friday, August 11, 2017. Given that the
SPP TPLTF has been actively developing guidance and processes for SPP and its members to address the approved TPL‐007‐1
standard, this open comment period offered an opportunity for the TPLTF to collectively review the proposed standard. Further, the
TPLTF assessed the TPL‐007‐2 official comment questionnaire and discussed potential industry responses. The following represents
a summary of the informal discussion conducted by the TPLTF and is provided to add value to those SPP members who choose to
submit comments during the open period. The information given here should be considered non‐binding and is intended to
supplement independent reviews of the proposed TPL‐007‐2, thereby adding the value of a TPLTF perspective.
If you have any questions, please contact the SPP TPLTF secretary Scott Jordan (SPP staff, sjordan@spp.org) or the SPP TPLTF
chairperson Chris Colson (WAPA‐UGPR, colson@wapa.gov).
General comment: Upon the TPLTF review of FERC Order No. 830, released in September 2016, it is clear that the FERC directives
are very prescriptive. The group felt that there was little leeway offered the Project 2013‐03 in drafting the proposed TPL‐007‐2
changes. Knowing this, the TPLTF review focused on the SDT approach to meeting the directives of FERC Order No. 830 and its
impact upon the SPP Planning Coordinator, as well as SPP member Transmission Planners, Transmission Owners, and Generator
Owners. The TPLTF took particular care to focus upon the draft requirements of TPL‐007‐2 and attempted to omit any discussion of
the FERC directives themselves, given that they are established in Order No. 830.
Questions from the TPL‐007‐2 Comment Form
1. The SDT developed proposed Requirements R8 – R10 and the supplemental GMD event to address FERC concerns with the
benchmark GMD event used in GMD Vulnerability Assessments. (Order No. 830 P.44, P.47‐49, P.65). The requirements will obligate
responsible entities to perform a supplemental GMD Vulnerability Assessment based on the supplemental GMD event that accounts
for potential impacts of localized peak geoelectric fields. Do you agree with the proposed requirements? If you do not agree, or if
you agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
TPLTF Discussion: The group agrees with the SDT approach to addressing FERC Order No. 830
Paragraph 44. In effect, the SDT has specified an extreme value for geoelectric field, called the supplemental GMD event, intended
to represent a locally‐enhanced geoelectric field experienced by a limited geographic area. In other words, the SDT has proposed a
means by which Planning Coordinators and Transmission Planners can approximate a non‐geospatially‐averaged peak geoelectric
field, thus meeting the intent of the FERC Order No. 830 directive. While determining peak geoelectric field amplitudes not based
solely on spatially‐averaged data is a significant challenge to meeting the FERC directive, primarily because of the lack of North
American data, as well as analytical tools available to Planning Coordinators and Transmission Planners, the group believes the SDT
has found a workable approach.
The group would like to note that it will be non‐trivial to apply the localized peak geoelectric field in the supplemental GMD event to
a spatially‐limited area, described in the proposed TPL‐007‐2
Attachment 1, given available software tools and available personnel resources. This will be especially pronounced for Planning
Coordinators and Transmission Planners with large geographical footprints. Many planning entities will be forced to apply the
supplemental peak geoelectric field over their entire area, in effect simply studying a higher magnitude benchmark GMD event.
While the group believes this is prominently conservative, as stated above, we understand and support the SDT approach to this
directive. It is likewise noted that the definition of a spatially‐limited area is absent in the materials published by the SDT, but this
vagary supports better analytical flexibility for Planning Coordinators and Transmission Planners and should not be defined in the
draft standard.
2. The SDT developed the Supplemental GMD Event Description white paper to provide technical justification for the supplemental
GMD event. The purpose of the supplemental GMD event description is to provide a defined event for assessing system
performance for a GMD event which includes a local enhancement of the geomagnetic field. Do you agree with the proposed
supplemental GMD event and the description in the white paper? If you do not agree, or if you agree but have comments or
suggestions for the supplemental GMD event and the description in the white paper provide your recommendation and explanation.
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TPLTF Discussion: The group recognizes that there are multiple methods to approach revisions to the benchmark GMD event
definition so that the reference peak geoelectric field amplitude component is not based solely on spatially‐averaged data (FERC
Order No. 830 Paragraph 44). However, given a wide diversity in available data, analytical tools, and personnel expertise, the group
believes that the SDT has found a practical approach to meeting the objective of the FERC directive. Moreover, the Supplemental
GMD Event Description white paper presents a reasoned justification for the use of the geoelectric field amplitude of 12 V/km.
The group recommends that the SDT consider a less ambiguous name for the Supplemental GMD Event; the group believes Extreme
Value GMD Event would be more appropriate for the following reasons:
a. Implies a closer relationship to the extreme events of TPL‐001‐4 for which Planning Coordinators and Transmission Planners
are familiar.
b. Is better aligned with the extreme value statistical analysis that was conducted to produce the subject reference peak
geoelectric field amplitude.
c. Indicates a measure of how rare the extreme value for the 1‐in‐100 year peak geoelectric field amplitude may be, based
upon the 95% confidence interval of the extreme value.
While the group agrees that the application of extreme value statistical methods presented in the Supplemental GMD Event
Description white paper is sound, three clarifying statements should be made in the white paper. Firstly, in short, the group agrees
that by using the 23 years of daily maximum geoelectric field amplitudes from IMAGE magnetometers, a proxy of higher magnitude
events can be characterized. It is noted that the southernmost magnetometer in the IMAGE chain resides in Suwałki, Poland at
54.01°N, whose geographic latitude places it roughly 500 miles north of Quebec. Given that geoelectric field is highly correlated
with geomagnetic latitude rather than geographic latitude, the IMAGE data should still be referred to as a loose approximation for
estimated North American geoelectric field magnitudes (Suwałki, Poland geomagnetic dipole latitude 52°N, Quebec geomagnetic
dipole latitude 56°N). In other words, the group believes it is appropriate to qualify that the extreme value analysis performed in the
white paper is based upon maximum data points obtained from an array of northern geomagnetically‐biased latitudes, further
inflated by using the high earth conductivity of Quebec. Secondly, it is well known that coastal geological conditions can lead to
locally‐enhanced geoelectric fields, not observed in regions more distant from the coast. Given that nearly all of the IMAGE chain
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magnetometers reside within 100 miles of the northern Atlantic Ocean or Baltic Sea coasts, it is reasonable to conclude that the
geoelectric field amplitudes derived from the corresponding IMAGE data may have suffered from geoelectric field enhancement
along conductivity boundaries. With respect to serving as a proxy for mainland North American peak geoelectric field amplitude, the
SDT should consider further qualifying the appropriateness of the IMAGE data which served as the foundation of the extreme value
analysis. Finally, the group agrees that the use of more resolute point over threshold (POT) methods was indicated over generalized
extreme value (GEV). For clarity, however, it should be emphasized that the geoelectric field amplitude of 12 V/km represents the
extreme value of the upper limit of the 95 percent confidence interval for a 100‐year return interval. In other words, the statistical
significance of the extreme value confidence interval is not equivalent to the statistic expressed by the confidence interval for the
data set consisting of 23 years of all sampled geoelectric field amplitudes (not shown). Each of these considerations, if addressed,
can strengthen the conclusions of the white paper by emphasizing its conservative approach.
3. The SDT established an 85 A per phase screening criterion for determining which power transformers are required to be assessed
for thermal impacts from a supplemental GMD event in Requirement R10. Justification for this threshold is provided in the revised
Screening Criterion for Transformer Thermal Impact Assessment white paper. Do you agree with the proposed 85 A per phase
screening criterion and the technical justification for this criterion that has been added to the white paper? If you do not agree, or if
you agree but have comments or suggestions for the screening criterion and revisions to the white paper provide your
recommendation and explanation.
TPLTF Discussion: Given the use of the 12 V/km geoelectric field amplitude for the supplemental GMD event, the group agrees with
the proposed 85 Amp threshold justified in the Screening Criterion for Transformer Thermal Impact Assessment white paper. The
group suggests that the proposed change on page 11 of the white paper stating “because the supplemental waveform has a sharper
peak, the peak metallic hot spot temperatures associated with the supplemental waveform are slightly lower than those associated
with the benchmark waveform” be clarified. In other words, this statement is counterintuitive given that the increased
supplemental time‐series waveform peak value implies higher GIC flows that, when experienced by a transformer will lead
potentially higher metallic hot spot temperatures. A suggested approach to better communicate this point is as follows:
Given that GICs are proportional to the time‐varying electric field, according to:
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|
|∙
sin
cos
(1)
The joule heating effect in transformers is proportional to the time‐varying GIC, as:
∝
,
,
(2)
It follows that the transformer metallic hot spot temperature is proportional to the time‐varying GIC, as:
∝
,
(3)
Therefore, the corresponding proportion that relates the transformer metallic hot spot temperature to time‐varying geoelectric field
amplitude is expressed by:
∝
(4)
The figure below shows the benchmark GMD and supplemental GMD event waveforms normalized to their respective geoelectric
field peak amplitudes. By portraying the two events in this manner, it is evident that the relationship given in (4) leads to a proxy
heating quantity for the benchmark GMD event approximately 32% more than the supplemental GMD event. Even though the peak
GIC induced by the supplemental GMD is higher than the benchmark, the total heating is less (integral).
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In other words, if the peak transformer GIC screening threshold were 75 A/phase for both events, the transformer suffering a
supplemental GMD event would experience less overall heating; the aggregated effects of the Supplemental geoelectric field
“intensity” is not sustained. Thus, the screening threshold for supplemental GMD event transformer GIC is established at a slightly
higher, but conservative, 85A/phase.
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4. The SDT revised the Transformer Thermal Impact Assessment white paper to include the supplemental GMD event. Do you agree
with the revisions to the white paper? If you do not agree, or if you agree but have comments or suggestions on the revisions to the
white paper provide your recommendation and explanation.
TPLTF Discussion: The group agrees with the changes in the Transformer Thermal Impact Assessment white paper, with the
exception of the explanation provided for Table 2 on page 5. Similar to the comment made regarding the counterintuitive language
in the Screening Criterion for Transformer Thermal Impact Assessment white paper, it is not clear why metallic hot spot
temperatures are reduced for the supplemental GMD event for the same effective GIC and transformer bulk oil temperature.
Additional clarity on this point would improve the ability of applicable entities to rely upon the reference data provided. The group
recommends adding white paper language similar to that suggested in Question Q3.
The group would like to highlight that the study of supplemental GMD event conditions may cause a significantly larger number of
transformers to be added for assessed by Transmission Owners and Generator Owners. Given that the analytical tools and modeling
software available for this type of analysis are limited, as well as the fact that most manufacturers supplying power transformers to
U.S. customers do not include data necessary to complete detailed thermal modeling with transformer test reports, the additional
effort to satisfy the supplemental GMD event analysis will be arduous. The group recommends that the SDT consider the reality that
these tools are merely in their infancy across the industry, and additional time to develop, deploy, and train on them should be
included in the TPL‐007‐2 implementation plan to complete transformer thermal assessments for the supplemental GMD event.
5. The SDT developed proposed Requirement R7 to address FERC directives in Order No. 830 for establishing Corrective Action Plan
(CAP) deadlines associated with GMD Vulnerability Assessments (P. 101, 102). Do you agree with the proposed requirement? If you
do not agree, or if you agree but have comments or suggestions for the proposed requirement provide your recommendation and
explanation.
TPLTF Discussion: Given the specificity of the Paragraphs 101 and 102 directives of FERC Order No. 830
Paragraph 44, the group believes that the SDT had little flexibility when developing the proposed language of Requirement R7. The
group agrees with the proposed Requirement R7, as presented. The group would like to reiterate the suggestion that the
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Supplemental GMD Event nomenclature be changed to Extreme Value GMD Event, as explained in the group’s discussion of
Question Q2.
6. The SDT developed Requirements R11 and R12 to address FERC directives in Order No. 830 for requiring responsible entities to
collect GIC monitoring and magnetometer data (P. 88; P. 90‐92). Do you agree with the proposed requirements? If you do not agree,
or if you agree but have comments or suggestions for the proposed requirements provide your recommendation and explanation.
TPLTF Discussion: Despite the added cost to implement additional monitoring and data collection, the group agrees that the SDT
developed a reasonable approach to the FERC directives in Order No. 830 Paragraph 88.
7. Do you agree with the proposed Implementation Plan for TPL‐007‐2? If you do not agree, or if you agree but have comments or
suggestions for the Implementation Plan provide your recommendation and explanation.
TPLTF Discussion: The group agrees with the proposed Implementation Plan for TPL‐007‐2 and does not see any conflicts with the
order by which the phased requirements become effective. However, given the lack of available tools, absence of thermal
modeling‐related data from transformer manufacturers, and the significant training that will be necessary to properly execute
transformer thermal assessments, the group believes that the implementation period for Requirement R10 should be at least 48
months after the standard is approved. This suggested implementation period is consistent with the existing implementation period
for Requirement R6 (transformer thermal assessment for benchmark GMD event) and should allow sufficient time for many more
transformers that may be observed to exceed the supplemental GMD event screening criterion.
8. Do you agree with the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for the requirements in proposed TPL‐007‐
2? If you do not agree, or if you agree but have comments or suggestions for the VRFs and VSLs provide your recommendation and
explanation.
TPLTF Discussion: The group agrees with the apportionment of the VRFs and VSLs.
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9. The SDT believes proposed TPL‐007‐2 provide entities with flexibility to meet the reliability objectives in the project Standards
Authorization Request (SAR) in a cost effective manner. Do you agree? If you do not agree, or if you agree but have suggestions for
improvement to enable additional cost effective approaches to meet the reliability objectives, please provide your recommendation
and, if appropriate, technical justification.
TPLTF Discussion: The group agrees that the SDT has done a good job of considering cost in time, resources, and personnel
commitment in meeting the objectives of the SAR, which were heavily prescribed by FERC Order No. 830. The group may not agree
with the perceived benefit to reliability that the additional effort to analyze the supplemental GMD event will yield, but the SDT has
proposed a solid means of addressing the FERC directives without relying on tools or methods that do not exist widely in industry
today. The group also supports the SDT cost‐effective approach to the proposed Requirement R7 which does not mention GIC
blocking devices as an integral part of a hardware mitigation. The group remains concerned with the perception that GIC mitigation
hardware is presently a viable solution. Given its cost, effects on Protection System design, as well as potential compromises to
existing BES reliability, GIC blocking devices may prove undesirable. The flexibility that the SDT has proposed in the development of
Corrective Action Plans is workable.
10. Provide any additional comments for the SDT to consider, if desired.
TPLTF Discussion: None additional.
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TPL‐007‐2 – 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
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
December 14, 2016
SAR posted for comment
December 16, 2016 –
January 20, 2017
45‐day formal comment period with initial ballot
June 28 – August 11,
2017
Anticipated Actions
Date
10‐day final ballot
October 2017
Board adoption
November 2017
Draft 2 of TPL‐007‐2
October 2017
Page 1 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL‐007‐2
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, wye‐
grounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL‐007‐2.
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‐007‐2 – 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: Long‐
term 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‐007‐2 – 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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TPL‐007‐2 – 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.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Rationale for Requirement 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 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.
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:
[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 in Part 7.4, for
implementing the selected actions from Part 7.1. The timetable shall:
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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 the control of the responsible entity determined
in Requirement R1 prevent implementation of the CAP within the timetable for
implementation provided in Part 7.3. The 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;
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. 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.
7.5. 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 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 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
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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)
Rationale for Requirements 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.
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.
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.
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8.4. 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. 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: (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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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.
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GMD Measurement Data Processes
Rationale for Requirements R11 and 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.
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.
R11. 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]
M11. 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 R11.
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R12. 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. 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 R12.
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, 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 R11 and R12, 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
1. System as may be
Benchmark GMD
postured in response
Event ‐ GMD Event to space weather
with Outages
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
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
Supplemental
GMD Event ‐ GMD
Event with
Outages
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‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R1.
Draft 2 of TPL‐007‐2
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Violation Severity Levels
Lower VSL
N/A
Moderate VSL
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.
Page 15 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R2.
R3.
Draft 2 of TPL‐007‐2
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Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
N/A
Severe VSL
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
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.
Page 16 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
R4.
Draft 2 of TPL‐007‐2
October 2017
Page 17 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R5.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
Draft 2 of TPL‐007‐2
October 2017
Page 18 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R6.
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
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.
Draft 2 of TPL‐007‐2
October 2017
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
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;
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
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;
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
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
Page 19 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
The responsible entity's
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
R7.
Draft 2 of TPL‐007‐2
October 2017
Moderate VSL
High VSL
Severe VSL
OR
The responsible entity failed
to include one of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
OR
The responsible entity failed
to include two of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
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 have a Corrective Action
Plan as required by
Requirement R7.
Page 20 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R8.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
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
two 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
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
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.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
four of the 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
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
Draft 2 of TPL‐007‐2
October 2017
Page 21 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R9.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
Draft 2 of TPL‐007‐2
October 2017
Page 22 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R10.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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.
Draft 2 of TPL‐007‐2
October 2017
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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;
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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 23 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
R11.
R12.
N/A
N/A
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.
N/A
N/A
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.
N/A
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
D. Regional Variances
None.
E. Associated Documents
Attachment 1
Draft 2 of TPL‐007‐2
October 2017
Page 24 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
2
Draft 2 of TPL‐007‐2
October 2017
Date
Action
December 17,
Adopted by the NERC Board of Trustees
2014
TBD
Revised to respond to directives in FERC
Order No. 830.
Change
Tracking
New
Revised
Page 25 of 43
TPL‐007‐2 – 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:
8
12
⁄
⁄
(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 is computed with the empirical expression:
0.001
.
(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‐2013‐
03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
Draft 2 of TPL‐007‐2
October 2017
Page 26 of 43
TPL‐007‐2 – 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
()
≤ 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‐Disturbance‐
Task‐Force‐(GMDTF)‐2013.aspx.
Draft 2 of TPL‐007‐2
October 2017
Page 27 of 43
TPL‐007‐2 – 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:
⁄8 for the benchmark GMD event
(4)
⁄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/.
5 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‐Disturbance‐
Mitigation.aspx.
Draft 2 of TPL‐007‐2
October 2017
Page 28 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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/.
Draft 2 of TPL‐007‐2
October 2017
Page 29 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
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
Draft 2 of TPL‐007‐2
October 2017
Page 30 of 43
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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.
Draft 2 of TPL‐007‐2
October 2017
Page 31 of 43
TPL‐007‐2 – 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)
Draft 2 of TPL‐007‐2
October 2017
Page 32 of 43
TPL‐007‐2 – 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
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‐Disturbance‐
Mitigation.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.
Draft 2 of TPL‐007‐2
October 2017
Page 33 of 43
TPL‐007‐2 – 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)
Draft 2 of TPL‐007‐2
October 2017
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TPL‐007‐2 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
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:
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
11 http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
12
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
13
Draft 2 of TPL‐007‐2
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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
Implementation Guidance16 for this requirement. This ERO‐Endorsed document is posted on the
NERC Compliance Guidance17 webpage.
14
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.
16 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.
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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.
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
18
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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.
19
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TPL‐007‐2 – Supplemental Material
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 Guidance22 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.
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
22 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.
Draft 2 of TPL‐007‐2
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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:
Draft 2 of TPL‐007‐2
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TPL‐007‐2 – 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
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).
26
27
http://www.intermagnet.org/index‐eng.php.
http://www.intermagnet.org/publications/intermag_4‐6.pdf.
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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.
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.
28
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
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TPL‐007‐2 – Supplemental Material
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 time‐
series 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
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
29
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.
31 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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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:
Corrective Action Plans are defined in the NERC Glossary of Terms:
A list of actions and an associated timetable for implementation to remedy a specific
problem.
Corrective Action Plans must, subject to the vulnerabilities identified in the assessments, contain
strategies for protecting against the potential impact of the benchmark GMD event, based on
factors such as the age, condition, technical specifications, system configuration, or location of
specific equipment. Chapter 5 of the NERC GMD Task Force Geomagnetic Disturbance Planning
Guide,33 December 2013 provides a list of mitigating measures that may be appropriate to
address an identified performance issue.
The provision of information in Requirement R7, Part 7.3 [Part 7.5 in TPL‐007‐2], shall be subject
to the legal and regulatory obligations for the disclosure of confidential and/or sensitive
information.
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.]
32
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
33
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TPL‐007‐2 – 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
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
December 14, 2016
SAR posted for comment
December 16, 2016 –
January 20, 2017
45‐day formal comment period with initial ballot
June 28 – August 11,
2017
Anticipated Actions
Date
45‐day formal comment period with ballot
June 2017
45‐day formal comment period with additional ballot
September 2017
10‐day final ballot
TBDOctober 2017
Board adoption
February
2018November 2017
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL‐007‐2
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, wye‐
grounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL‐007‐1 2.
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‐007‐2 – 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: Long‐
term 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‐007‐2 – 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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TPL‐007‐2 – 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
benchmark GIC valuevalues 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.
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Rationale for Requirement 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 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.
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:
[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 in Part 7.4, for
implementing the selected actions from Part 7.1. The timetable shall:
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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 the control of the responsible entity determined
in Requirement R1 prevent implementation of the CAP within the timetable for
implementation provided in Part 7.3. The 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;
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. 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.
7.5. 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 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 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
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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)
Rationale for Requirements R8 ‐– R10: The proposed requirements address directives in
Order No. 830 for revising the benchmark GMD event used in GMD Vulnerability
Assessments (P .44, P47P 47‐49). The requirements add a supplemental GMD
Vulnerability Assessment based on the supplemental GMD event that accounts for
localized peak geoelectric fields.
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.
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.
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8.4. 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. 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: (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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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
supplemental GIC valuevalues 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.
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GMD Measurement Data Processes
Rationale for Requirements R11 and 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).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 69 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.
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.
R11. 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]
M11. 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 R11.
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R12. 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. 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 R12.
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, 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 R11 and R12, 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
1. System as may be
Benchmark GMD
postured in response
Event ‐ GMD Event to space weather
with Outages
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
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
Supplemental
GMD Event ‐ GMD
Event with
Outages
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.
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Violation Severity Levels
Lower VSL
N/A
PageOctober 2017
Moderate VSL
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.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R2.
R3.
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Violation Severity Levels
Lower VSL
N/A
N/A
PageOctober 2017
Moderate VSL
High VSL
Severe VSL
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 study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not maintain both 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.
N/A
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.
N/A
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Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
R4.
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Violation Severity Levels
R#
R5.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
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R6.
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
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.
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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
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;
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
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;
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
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
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Violation Severity Levels
R#
Lower VSL
The responsible entity's
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
R7.
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Moderate VSL
High VSL
Severe VSL
OR
The responsible entity failed
to include one of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
OR
The responsible entity failed
to include two of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
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 have a Corrective Action
Plan as required by
Requirement R7.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R8.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment;
OR
.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;
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two 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
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
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.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
four of the 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
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R9.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R10.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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.
Draft 12 of TPL‐007‐2
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PageOctober 2017
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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;
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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;
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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 23 of 46
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11.
R12.
Violation Severity Levels
Lower VSL
N/A
N/A
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.
N/A
N/A
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.
N/A
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
D. Regional Variances
None.
E. Associated Documents
None.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Draft 12 of TPL‐007‐2
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
2
Draft 12 of TPL‐007‐2
June 2017
Date
Action
December 17,
Adopted by the NERC Board of Trustees
2014
TBD
Revised to respond to directives in FERC
Order No. 830.
PageOctober 2017
Change
Tracking
New
Revised
Page 26 of 46
TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Attachments
The following attachments are part of TPL‐007‐2.
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TPL‐007‐2 – 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:
8
12
⁄
⁄
(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 is computed with the empirical expression:
0.001
.
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
1 The benchmark GMD event descriptionBenchmark Geomagnetic Disturbance Event Description, May 2016 is available on the
Related Information pagewebpage 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 GMD Geomagnetic Disturbance Event Description, October 2017 white paper on
the Project 2013‐03 Geomagnetic Disturbance Mitigation project pagewebpage:
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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TPL‐007‐2 – 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
()
≤ 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‐Disturbance‐
Task‐Force‐(GMDTF)‐2013.aspxpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic‐Disturbance‐Task‐Force‐(GMDTF)‐
2013.aspx.
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TPL‐007‐2 – 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:
⁄8 for the benchmark GMD event
(4)
⁄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/http://geomag.usgs.gov/conductivity/.
5 See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013‐03 Geomagnetic
Disturbance Mitigation project pagewebpage: http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐
Disturbance‐Mitigation.aspx.
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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
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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TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
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 (FL‐
1FL1) 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
NRCan’sthe 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 GMDGeomagnetic 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 pagewebpage for TPL‐007‐
1: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
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TPL‐007‐2 – 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)
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TPL‐007‐2 – 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
Event9
The geomagnetic field measurement record of the March 13‐14, 1989 GMD event, measured at
NRCan’sthe 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
GMDGeomagnetic 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‐Disturbance‐
Mitigation.aspxhttp://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project pagewebpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic‐Disturbance‐Task‐Force‐(GMDTF)‐2013.aspx.
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TPL‐007‐2 – 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)
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TPL‐007‐2 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
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. AThe Benchmark
Geomagnetic Disturbance Event Description, May 201611 white paper that includes the event
description, analysis, and example calculations is available on the Project 2013‐03 Geomagnetic
Disturbance Mitigation project page at:.
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. AThe Supplemental
Geomagnetic Disturbance Event Description, October 201712 white paper that includes the event
description and analysis is available on the Project 2013‐03 Geomagnetic Disturbance Mitigation
project page:.
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. The
guide is available at: , 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
11 http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
12
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
13
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TPL‐007‐2 – 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 GMDGeomagnetic Disturbance Planning Guide,14 December 2013 developed by the NERC
GMD Task Force provides technical information on GMD‐specific considerations for planning
studies. It is available at:
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 thermal impact assessment white
paperTransformer 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. TheWhite Paper ERO
enterprise has endorsed the white paper asEnterprise‐Endorsed Implementation Guidance16 for
14
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.
16 http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL‐007‐1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
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TPL‐007‐2 – Supplemental Material
this requirement. The white paperThis ERO‐Endorsed document is posted on the NERC
compliance guidance page:Compliance Guidance17 webpage.
http://www.nerc.com/pa/comp/guidance/Pages/default.aspx
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 posted on the Related Information page for TPL‐007‐
1.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 GMDGeomagnetic 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 GMDGeomagnetic Disturbance Planning Guide,21 December 2013 developed by the NERC
GMD Task Force provides technical information on GMD‐specific considerations for planning
studies. It is available at:
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.
17
http://www.nerc.com/pa/comp/guidance/Pages/default.aspx.
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.
18
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TPL‐007‐2 – 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 paperWhite Paper ERO
Enterprise‐Endorsed Implementation Guidance22 discussed in the Requirement R6 section above.
A revisedlater version of the Transformer Thermal Impact Assessment white paperWhite Paper,23
October 2017, has been developed to include updated information pertinent to the
supplemental GMD event and supplemental thermal impact assessment. This revised white
paper is posted on the project page at:
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 posted on the project page.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 NERC 2012
GMDSpecial Reliability Assessment Interim Report (see Chapter 6).: Effects of Geomagnetic
Disturbances on the Bulk‐Power System, 25 February 2012. GIC monitoring is generally performed
22 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.
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TPL‐007‐2 – Supplemental Material
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 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).
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TPL‐007‐2 – Supplemental Material
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
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 IntermagnetINTERMAGNET Technical
Reference Manual, which is available at:Version 4.6, 2012.27
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.
26
27
http://www.intermagnet.org/index‐eng.php.
http://www.intermagnet.org/publications/intermag_4‐6.pdf.
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TPL‐007‐2 – Supplemental Material
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 GIC Application Guide
Computing Geomagnetically‐Induced Current in the Bulk‐Power System,28 December 2013,
developed by the NERC GMD Task Force and available at: .
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.
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.
28
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
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TPL‐007‐2 – Supplemental Material
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 GMDGeomagnetic Disturbance Planning Guide,29 December 2013 developed by the NERC
GMD Task Force provides technical information on GMD‐specific considerations for planning
studies. It is available at:
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 time‐
series 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: White Paper,30 October
2017.
[http://www.nerc.com/pa/comp/guidance/Pages/default.aspx]
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.
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
29
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.
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TPL‐007‐2 – Supplemental Material
justification is provided in the Thermal Screening Criterion white paperfor 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 posted on the project
pageWhite 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:
Corrective Action Plans are defined in the NERC Glossary of Terms:
A list of actions and an associated timetable for implementation to remedy a specific
problem.
Corrective Action Plans must, subject to the vulnerabilities identified in the assessments, contain
strategies for protecting against the potential impact of the benchmark GMD event, based on
factors such as the age, condition, technical specifications, system configuration, or location of
specific equipment. Chapter 5 of the NERC GMD Task Force GMDGeomagnetic Disturbance
Planning Guide,33 December 2013 provides a list of mitigating measures that may be appropriate
to address an identified performance issue.
The provision of information in Requirement R7, Part 7.3 [Part 7.5 in TPL‐007‐2], shall be subject
to the legal and regulatory obligations for the disclosure of confidential and/or sensitive
information.
31
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.
33 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
32
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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.]
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TPL‐007‐1 —2 – 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
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
December 14, 2016
SAR posted for comment
December 16, 2016 –
January 20, 2017
45‐day formal comment period with initial ballot
June 28 – August 11,
2017
Anticipated Actions
Date
10‐day final ballot
October 2017
Board adoption
November 2017
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TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
New or Modified Term(s) Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):
None
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TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL‐007‐12
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, wye‐
grounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL‐007‐2.
5.6. 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.
6.
Effective Date:
See Implementation Plan for TPL‐007‐1
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 and, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessment(s).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‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. 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 and, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessment(s),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 Assessment(s). Assessments. [Violation Risk Factor: High] [Time
Horizon: Long‐term Planning]
M2. 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
Assessment(s).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
benchmark GMD eventevents described in Attachment 1. [Violation Risk Factor:
Medium] [Time Horizon: Long‐term Planning]
M3. 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‐007‐1 —2 – 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 within 90
calendar days of completion: (i) to the responsible entity’s Reliability
Coordinator, adjacent Planning Coordinators, and adjacent Transmission
Planners, and 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. 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. 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 within 90 calendar days of completion: (i) to itsthe responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), Coordinators, and adjacent
Transmission Planner(s), and Planners within 90 calendar days of completion, and (ii)
to any functional entity who has submittedthat 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 transformerbenchmark 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]
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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. 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 valuevalues 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. 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.
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Rationale for Requirement 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 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.
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 offor 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
Corrective Action PlanCAP 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 Special
Protection Systems. Remedial Action Schemes.
Use of Operating Procedures, specifying how long they will be needed as
part of the Corrective Action Plan. CAP.
Use of Demand‐Side Management, new technologies, or other initiatives.
7.2. Be reviewed in subsequentdeveloped within one year of completion of the
benchmark GMD Vulnerability Assessments until it isAssessment.
7.3. Include a timetable, subject to revision by the responsible entity in Part 7.4, for
implementing the selected actions from Part 7.1. The timetable shall:
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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.
7.2.7.4.
Be revised if situations beyond the control of the responsible entity
determined that the System meets the performance requirements contained in
Table 1.Requirement R1 prevent implementation of the CAP within the timetable
for implementation provided in Part 7.3. The 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;
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. 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.
7.3.7.5.
Be provided within 90 calendar days of completion: (i) to the responsible
entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent
Transmission Planner(s), and functional entities referenced in the Corrective
Action Plan, andCAP 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.
7.3.1.7.5.1. If a recipient of the Corrective Action PlanCAP 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.
M7. 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 of
for the steady state planning benchmark GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its Corrective Action PlanCAP
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,
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web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its Corrective Action PlanCAP or relevant information,
if any, within 90 calendar days of its completion(i) to itsthe responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), aand functional entityentities referenced in the Corrective Action Plan,
andCAP 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 Corrective Action PlanCAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
Table 1 –Steady State Planning Events
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the planning event.
c. Planned System adjustments such as Transmission configuration changes and re‐dispatch of generation are allowed if
are executable within the time duration applicable to the Facility Ratings.
Category
GMD
GMD Event
with Outages
Initial Condition
1. System as may be
postured in response to
space weather
information1, and then
2. GMD event2
Event
Interruption of
Firm Transmission
Service Allowed
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
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 planning event are described in Attachment 1 (Benchmark GMD Event).
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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. Rationale for Requirements 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.
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.
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. 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. 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.
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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: (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.
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.
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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.
GMD Measurement Data Processes
Rationale for Requirements R11 and 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.
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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.
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.
R11. 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]
M11. 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 R11.
R12. 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. 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 R12.
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
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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, 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 R11 and R12, 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
1. System as may be
Benchmark GMD
postured in response
Event ‐ GMD Event to space weather
with Outages
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
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
Supplemental
GMD Event ‐ GMD
Event with
Outages
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.
Draft 2 of TPL‐007‐2
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Violation Severity Levels
Lower VSL
N/A
Moderate VSL
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.
Page 16 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R2.
R3.
Draft 2 of TPL‐007‐2
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Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
N/A
Severe VSL
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
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.
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Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
last benchmark GMD
Vulnerability Assessment.
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
last benchmark GMD
Vulnerability Assessment.
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
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
R4.
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Violation Severity Levels
R#
R5.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
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R6.
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
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.
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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
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;
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
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;
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
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
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Violation Severity Levels
R#
Lower VSL
The responsible entity's
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
R7.
Draft 2 of TPL‐007‐2
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Moderate VSL
High VSL
Severe VSL
OR
The responsible entity failed
to include one of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
OR
The responsible entity failed
to include two of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
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 have a Corrective Action
Plan as required by
Requirement R7.
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Violation Severity Levels
R#
R8.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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
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
two 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
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
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.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
four of the 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
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
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Violation Severity Levels
R#
R9.
Lower VSL
Moderate VSL
High VSL
Severe VSL
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.
Draft 2 of TPL‐007‐2
October 2017
Page 23 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R10.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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.
Draft 2 of TPL‐007‐2
October 2017
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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;
The responsible entity failed
to conduct a supplemental
thermal impact assessment
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 24 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
R11.
R12.
N/A
N/A
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.
N/A
N/A
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.
N/A
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
D. Regional Variances
None.
E. Associated Documents
Attachment 1
Draft 2 of TPL‐007‐2
October 2017
Page 25 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
2
Draft 2 of TPL‐007‐2
October 2017
Date
Action
December 17,
Adopted by the NERC Board of Trustees
2014
TBD
Revised to respond to directives in FERC
Order No. 830.
Change
Tracking
New
Revised
Page 26 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD
EventEvents
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 waveshapewaveform 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 relationshiprelationships:
Epeak
(V/km)
8
(1)
12
⁄
⁄
(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 event isevents are defined for geomagnetic latitude of
60 and it 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:
(2)
1 The benchmark GMD event description is available on the Project 2013‐03Benchmark 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.pdfMitigation project page:.
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‐2013‐
03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
Page 27 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
0.001
.
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
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
(23) 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 AssessmentAssessments. When a ground conductivity model is not
3 Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic‐Disturbance‐
Task‐Force‐(GMDTF)‐2013.aspxpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic‐Disturbance‐Task‐Force‐(GMDTF)‐
2013.aspx.
Page 28 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
available, the planning entity should use the largest β factor of adjacent physiographic
regions or a technically justified value.
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:
/8
(3)
⁄8 for the benchmark GMD event
(4)
⁄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.
4 Available at http://geomag.usgs.gov/conductivity/http://geomag.usgs.gov/conductivity/.
Page 29 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
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.
Figure 1: Physiographic Regions of the Continental United States6
5 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‐Disturbance‐
Mitigation.aspx.
6 Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/ ().
Page 30 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 2: Physiographic Regions of Canada
Table 3 Geoelectric Field Scaling Factors
USGS
Scaling Factor
Earth model
()
AK1A
AK1B
AP1
0.56
0.56
0.33
Page 31 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
AP2
BR1
CL1
CO1
CP1
CP2
FL1
CS1
IP1
IP2
IP3
IP4
NE1
PB1
PB2
PT1
0.82
0.22
0.76
0.27
0.81
0.95
0.74
0.41
0.94
0.28
0.93
0.41
0.81
0.62
0.46
Figure 1: Physiographic Regions of the Continental United States71.17
SL1
SU1
BOU
FBK
PRU
BC
PRAIRIES
SHIELD
ATLANTIC
0.53
0.93
0.28
0.56
0.21
0.67
0.96
1.0
0.79
7 Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/ ().
Page 32 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 4 Reference Earth Model (Quebec)
Figure 2: Physiographic Regions of Canada
Table 3: Geoelectric Field Scaling Factors
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
Page 33 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Earth model
Scaling Factor
Benchmark Event
(b)
Scaling Factor
Supplemental
Event
(s)
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
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
Page 34 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
∞
3
Reference Geomagnetic Field Time Series or Waveshape8 Waveform for the Benchmark
GMD Event9
The geomagnetic field measurement record of the March 13‐14 1989 GMD event, measured at
NRCan’sthe NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic
field waveshapewaveform 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
amplitudeamplitudes 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).
SamplingThe sampling rate for the geomagnetic field waveshapewaveform 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 benchmark conductivity scaling factor .b.
Refer to the Benchmark GMD Event Description for details on the determination of the reference geomagnetic
field waveshape: http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐
Mitigation.aspx
8
9 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.
10 The data file of the benchmark geomagnetic field waveshapewaveform is available on the NERC GMD Task Force project
pageRelated Information webpage for TPL‐007‐1: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
Page 35 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveshape. Red Bn (Northward), Blue Be (Eastward)
Figure 4: Benchmark Geoelectric Field Waveshape ‐ EE (Eastward)
Page 36 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 5: Benchmark Geoelectric Field Waveshape – EN (Northward)
Page 37 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
C.A.
1.
Compliance
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards
1.2.
Evidence Retention
The following evidence retention periods 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 CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner, and
Generator Owner 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, and R6, each responsible entity shall retain
documentation as evidence for five years.
For Requirement R4, each responsible entity shall retain documentation of the
current GMD Vulnerability Assessment and the preceding GMD Vulnerability
Assessment.
For Requirement R7, 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.
If a Planning Coordinator, Transmission Planner, Transmission Owner, or
Generator Owner is found non‐compliant it shall keep information related to the
non‐compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3.
Compliance Monitoring and Assessment Processes:
Compliance Audits
Self‐Certifications
Spot Checking
Compliance Investigations
Self‐Reporting
Complaints
Page 38 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
1.4.
Additional Compliance Information
None
Page 39 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
Long‐term
Planning
Lower
N/A
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
and performing the
study or studies
needed to complete
GMD Vulnerability
Assessment(s).
R2
Long‐term
Planning
High
N/A
N/A
The responsible entity
did not maintain
either System models
or GIC System models
of the responsible
The responsible entity
did not maintain both
System models and
GIC System models of
the responsible
Page 40 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
entity’s planning area
for performing the
study or studies
needed to complete
GMD Vulnerability
Assessment(s).
R3
Long‐term
Planning
Medium N/A
N/A
R4
Long‐term
Planning
High
The responsible
entity's completed
GMD Vulnerability
Assessment failed to
satisfy one of
elements listed in
Requirement R4, Parts
4.1 through 4.3;
The responsible entity
completed a GMD
Vulnerability
Assessment, but it
was more than 60
calendar months and
less than or equal to
64 calendar months
since the last GMD
Vulnerability
Assessment.
N/A
The responsible
entity's completed
GMD Vulnerability
Assessment failed to
satisfy two of the
elements listed in
Requirement R4, Parts
4.1 through 4.3;
OR
OR
The responsible entity
The responsible entity completed a GMD
completed a GMD
Vulnerability
Vulnerability
Assessment, but it
Assessment, but it
entity’s planning area
for performing the
study or studies
needed to complete
GMD Vulnerability
Assessment(s).
The responsible entity
did not have criteria
for acceptable System
steady state voltage
performance for its
System during the
benchmark GMD
event described in
Attachment 1 as
required.
The responsible
entity's completed
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 GMD
Vulnerability
Assessment, but it
Page 41 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
was more than 64
calendar months and
less than or equal to
68 calendar months
since the last GMD
Vulnerability
Assessment.
was more than 68
calendar months and
less than or equal to
72 calendar months
since the last GMD
Vulnerability
Assessment.
was more than 72
calendar months since
the last GMD
Vulnerability
Assessment;
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.
R5
Long‐term
Planning
Medium 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.
OR
The responsible entity
does not have a
completed GMD
Vulnerability
Assessment.
Page 42 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R6
Long‐term
Planning
Medium The responsible entity
failed to conduct a
thermal impact
assessment 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 R5, Part
5.1, is 75 A or greater
per phase;
OR
The responsible entity
conducted a 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
The responsible entity
failed to conduct a
thermal impact
assessment 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 R5, Part
5.1, is 75 A or greater
per phase;
OR
The responsible entity
conducted a 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
The responsible entity
failed to conduct a
thermal impact
assessment 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 R5, Part
5.1, is 75 A or greater
per phase;
OR
The responsible entity
conducted a 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
The responsible entity
failed to conduct a
thermal impact
assessment 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 R5, Part
5.1, is 75 A or greater
per phase;
OR
The responsible entity
conducted a 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
Page 43 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R7
Long‐term
Planning
High
or equal to 26
calendar months of
receiving GIC flow
information specified
in Requirement R5,
Part 5.1.
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 required
elements as listed in
Requirement R6, Parts
6.1 through 6.3.
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 required
elements as listed in
Requirement R6, Parts
6.1 through 6.3.
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 in
Requirement R6, Parts
6.1 through 6.3.
N/A
The responsible
entity's Corrective
Action Plan failed to
comply with one of
the elements in
Requirement R7, Parts
7.1 through 7.3.
The responsible
entity's Corrective
Action Plan failed to
comply with two of
the elements in
Requirement R7, Parts
7.1 through 7.3.
The responsible
entity's Corrective
Action Plan failed to
comply with all three
of the elements in
Requirement R7, Parts
7.1 through 7.3;
OR
The responsible entity
did not have a
Corrective Action Plan
as required by
Requirement R7.
Page 44 of 58
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.
Regional Variances
None.
E. Interpretations
None.
F.A.
Associated Documents
None.
Version History
Version
Date
1
December 17, 2014
Action
Adopted by the NERC Board of Trustees
Figure 3: Benchmark Geomagnetic Field Waveform
Red Bn (Northward), Blue Be (Eastward)
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Change Tracking
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 4: Benchmark Geoelectric Field Waveform
EE (Eastward)
Figure 5: Benchmark Geoelectric Field Waveform
EN (Northward)
Page of
TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event11
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.12 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.
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)
11 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‐Disturbance‐
Mitigation.aspx.
12 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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TPL‐007‐1 —2 – Transmission System Planned Performance for Geomagnetic Disturbance Events
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue EN (Northward), Red EE (Eastward)
Page of
TPL‐007‐2 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
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. AThe Benchmark
Geomagnetic Disturbance Event Description, May 201613 white paper that includes the event
description, analysis, and example calculations is available on the Project 2013‐03 Geomagnetic
Disturbance Mitigation project page:.
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 201714 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. The
guide is available at: , December 2013.15
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
13 http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
14
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
15
Page of
TPL‐007‐2 – Supplemental Material
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 GMDGeomagnetic Disturbance Planning Guide,16 December 2013 developed by the NERC
GMD Task Force provides technical information on GMD‐specific considerations for planning
studies. It is available at:
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
Requirement R5
The transformerbenchmark thermal impact assessment of transformers specified in
Requirement R6 is based on GIC information for the Benchmarkbenchmark 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 transformerthe 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 transformerthe 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 thermal impact
assessment white paperTransformer Thermal Impact Assessment White Paper,17 October 2017.
16
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
17 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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TPL‐007‐2 – Supplemental Material
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 posted on the project
pageWhite Paper ERO Enterprise‐Endorsed Implementation Guidance18 for this requirement. This
ERO‐Endorsed document is posted on the NERC Compliance Guidance19 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 posted on the project page.White Paper,20 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 GMDGeomagnetic Disturbance Planning Guide,21
December 2013. Additional information is available in the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk‐Power System:, 22 February 2012.
Requirement R8
The Geomagnetic Disturbance Planning Guide,23 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.
18 http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL‐007‐1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
19 http://www.nerc.com/pa/comp/guidance/Pages/default.aspx.
20 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
21 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
22 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
23 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
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TPL‐007‐2 – Supplemental Material
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 Enterprise‐Endorsed
Implementation Guidance24 discussed in the Requirement R6 section above. A later version of the
Transformer Thermal Impact Assessment White Paper,25 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,26 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.
24 http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL‐007‐1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
25 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
26 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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TPL‐007‐2 – Supplemental Material
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, 27 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 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.
27 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
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TPL‐007‐2 – Supplemental Material
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:28
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, 2012.29
Rationale:
During development of this standardTPL‐007‐1, text boxes were embedded within the standard
to explain the rationale for various parts of the standard. Upon BOT approval, theThe 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.
28
29
http://www.intermagnet.org/index‐eng.php.
http://www.intermagnet.org/publications/intermag_4‐6.pdf.
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TPL‐007‐2 – Supplemental Material
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 GIC Application Guide
Computing Geomagnetically‐Induced Current in the Bulk‐Power System,30 December 2013,
developed by the NERC GMD Task Force and available at: .
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.
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.
30
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
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TPL‐007‐2 – Supplemental Material
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 GMDGeomagnetic Disturbance Planning Guide,31 December 2013 developed by the NERC
GMD Task Force provides technical information on GMD‐specific considerations for planning
studies. It is available at:
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
time‐series 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: White Paper,32
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
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.
31
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
32 http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
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TPL‐007‐2 – Supplemental Material
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 Thermal Screening Criterion white paperfor Transformer Thermal
Impact Assessment White Paper,33 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 posted on the project
pageWhite Paper,34 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:
Corrective Action Plans are defined in the NERC Glossary of Terms:
A list of actions and an associated timetable for implementation to remedy a specific
problem.
Corrective Action Plans must, subject to the vulnerabilities identified in the assessments, contain
strategies for protecting against the potential impact of the Benchmarkbenchmark GMD event,
based on factors such as the age, condition, technical specifications, system configuration, or
location of specific equipment. Chapter 5 of the NERC GMD Task Force GMDGeomagnetic
Disturbance Planning Guide,35 December 2013 provides a list of mitigating measures that may be
appropriate to address an identified performance issue.
33
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.
35 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
34
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TPL‐007‐2 – Supplemental Material
The provision of information in Requirement R7, Part 7.3, [Part 7.5 in TPL‐007‐2], shall be subject
to the legal and regulatory obligations for the disclosure of confidential and/or sensitive
information.
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.]
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Reliability Standard TPL-007-2
Applicable Standard
TPL‐007‐2 ‐ Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
TPL‐007‐1 ‐ 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 September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL‐007‐1 and its associated five‐year Implementation Plan. In the
Order, FERC also directed NERC to develop certain modifications to the standard. FERC established a
deadline of 18 months from the effective date of Order No. 830 for completing the revisions, which
is May 2018.
General Considerations
This Implementation Plan is intended to integrate the new requirements in TPL‐007‐2 with the GMD
Vulnerability Assessment process that is being implemented through approved TPL‐007‐1. At the
time of the May 2018 filing deadline, many requirements in approved standard TPL‐007‐1 that lead
to completion of the geomagnetic disturbance (GMD) Vulnerability Assessment will be in effect.
Furthermore, many entities may be taking steps to complete studies or assessments that are
required by future enforceable requirements in TPL‐007‐1. The Implementation Plan phases in the
requirements in TPL‐007‐2 based on the effective date of TPL‐007‐2, as follows:
Effective Date before January 1, 2021. Implementation timeline supports applicable entities
completing new requirements for supplemental GMD Vulnerability Assessments
concurrently with requirements for the benchmark GMD Vulnerability Assessment
(concurrent effective dates).
Effective Date on or after January 1, 2021. Implementation timeline supports applicable
entities completing the benchmark GMD Vulnerability Assessments before new
requirements for supplemental GMD Vulnerability Assessments become effective.
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.
Standard TPL‐007‐2
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 three (3) 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 three (3) 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
If TPL-007-2 becomes effective before January 1, 2021
Implementation timeline supports applicable entities completing new requirements for
supplemental GMD Vulnerability Assessments concurrently with requirements for the benchmark
GMD Vulnerability Assessment (concurrent effective dates).
Compliance Date for TPL‐007‐2 Requirements R1 and R2
Entities shall be required to comply with Requirements R1 and R2 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R5
Entities shall not be required to comply with Requirements R5 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
2
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R11 and R12
Entities shall not be required to comply with Requirements R11 and R12 until 24 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until 30 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until 42 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R7
Entities shall not be required to comply with Requirement R7 until 54 months after the effective
date of Reliability Standard TPL‐007‐2.
If TPL-007-2 becomes effective on or after January 1, 2021
Implementation timeline supports applicable entities completing the benchmark GMD Vulnerability
Assessments before new requirements for supplemental GMD Vulnerability Assessments become
effective.
Compliance Date for TPL‐007‐2 Requirements R1, R2, R5, and R6
Entities shall be required to comply with Requirements R1, R2, R5, and R6 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3 and R4
Entities shall not be required to comply with Requirements R3 and R4 until 12 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R7, R11, and R12
Entities shall not be required to comply with Requirements R7, R11, and R12 until 24 months after
the effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until 36 months after the effective
date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
3
Compliance Date for TPL‐007‐2 Requirement R10
Entities shall not be required to comply with Requirement R10 until 60 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R8
Entities shall not be required to comply with Requirement R8 until 72 months after the effective
date of Reliability Standard TPL‐007‐2.
Retirement Date
Standard TPL‐007‐1
Reliability Standard TPL‐007‐1 shall be retired immediately prior to the effective date of TPL‐007‐2 in
the particular jurisdiction in which the revised standard is becoming effective, provided that the TPL‐
007‐1 Implementation Plan shall remain in effect to the extent necessary until the phased‐in
compliance dates above are implemented for TPL‐007‐2.
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 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
4
Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Reliability Standard TPL-007-2
Applicable Standard(s)
TPL‐007‐2 ‐ Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement(s)
TPL‐007‐1 ‐ Transmission System Planned Performance for Geomagnetic Disturbance Events
Prerequisite Standard(s)
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 September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL‐007‐1 and its associated five‐year Implementation Plan. In the
Order, FERC also directed NERC to develop certain modifications to the standard. FERC established a
deadline of 18 months from the effective date of Order No. 830 for completing the revisions, which
is May 2018.
General Considerations
This Implementation Plan is intended to integrate the new requirements in TPL‐007‐2 with the GMD
Vulnerability Assessment process that is being implemented through approved TPL‐007‐1. At the
time of the May 2018 filing deadline, many requirements in approved standard TPL‐007‐1 that lead
to completion of the GMDgeomagnetic disturbance (GMD) Vulnerability Assessment will be in
effect. Furthermore, many entities may be taking steps to complete studies or assessments that are
required by future enforceable requirements in TPL‐007‐1. The Implementation Plan phases in the
requirements in TPL‐007‐2 based on the effective date of TPL‐007‐2, as follows:
Effective Date before January 1, 2021. Implementation timeline supports applicable entities
completing new requirements for supplemental GMD Vulnerability Assessments
concurrently with requirements for the benchmark GMD Vulnerability Assessment
(concurrent effective dates).
Effective Date on or after January 1, 2021. Implementation timeline supports applicable
entities completing the benchmark GMD Vulnerability Assessments before new
requirements for supplemental GMD Vulnerability Assessments become effective.
Effective Date and Phased-In Compliance Dates
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 athe proposed Reliability Standard (e.g., an entire Requirement or a portion
thereof), the additional time for compliance with that section is specified below. TheThese phased‐
in compliance date for those particular sections representsdates represent the datedates 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.
Standard TPL‐007‐2
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 three (3) 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 three (3) 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
If TPL-007-2 becomes effective before January 1, 2021
Implementation timeline supports applicable entities completing new requirements for
supplemental GMD Vulnerability Assessments concurrently with requirements for the benchmark
GMD Vulnerability Assessment (concurrent effective dates).
Compliance Date for TPL‐007‐2 Requirements R1 and R2
Entities shall be required to comply with Requirements R1 and R2 upon the effective date of
Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 GMDGeomagnetic Disturbance Mitigation | JuneOctober 2017
2
Compliance Date for TPL‐007‐2 Requirement R5
Entities shall not be required to comply with Requirements R5 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R11 and R12
Entities shall not be required to comply with Requirements R11 and R12 until 24 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until 30 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until 42 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R7
Entities shall not be required to comply with Requirement R7 until 54 months after the effective
date of Reliability Standard TPL‐007‐2.
If TPL-007-2 becomes effective on or after January 1, 2021
Implementation timeline supports applicable entities completing the benchmark GMD Vulnerability
Assessments before new requirements for supplemental GMD Vulnerability Assessments become
effective.
Compliance Date for TPL‐007‐2 Requirements R1, R2, R5, and R6
Entities shall be required to comply with Requirements R1, R2, R5, and R6 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3 and R4
Entities shall not be required to comply with Requirements R3 and R4 until 12 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R7, R11, and R12
Entities shall not be required to comply with Requirements R7, R11, and R12 until 24 months after
the effective date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 GMDGeomagnetic Disturbance Mitigation | JuneOctober 2017
3
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until 36 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R10
Entities shall not be required to comply with Requirement R10 until 60 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R8
Entities shall not be required to comply with Requirement R8 until 72 months after the effective
date of Reliability Standard TPL‐007‐2.
Retirement Date
Standard TPL‐007‐1
Reliability Standard TPL‐007‐1 shall be retired immediately prior to the effective date of TPL‐007‐2 in
the particular jurisdiction in which the revised standard is becoming effective, provided that the TPL‐
007‐1 Implementation Plan shall remain in effect to the extent necessary until the phased‐in
compliance dates above are implemented for TPL‐007‐2.
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 2013‐03 GMDGeomagnetic Disturbance Mitigation | JuneOctober 2017
4
Supplemental
Geomagnetic
Disturbance Event
Description
Project 2013-03 GMD Mitigation
October 2017
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
General Characteristics .......................................................................................................................................... iv
Supplemental GMD Event Description ...................................................................................................................... 1
Supplemental GMD Event Geoelectric Field Amplitude ........................................................................................ 1
Supplemental Geomagnetic Field Waveform ........................................................................................................ 1
Appendix I – Technical Considerations ...................................................................................................................... 3
Statistical Considerations ....................................................................................................................................... 3
Extreme Value Analysis ...................................................................................................................................... 3
Spatial Considerations ........................................................................................................................................... 7
Local Enhancement Waveform ............................................................................................................................ 13
Transformer Thermal Assessment ....................................................................................................................... 15
Appendix II – Scaling the Supplemental GMD Event ............................................................................................... 16
Scaling the Geomagnetic Field ............................................................................................................................. 16
Scaling the Geoelectric Field ................................................................................................................................ 17
References ............................................................................................................................................................... 21
NERC | Supplemental GMD Event Description | October 2017
ii
Preface
The North American Electric Reliability Corporation (NERC) is a not‐for‐profit international regulatory authority
whose mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC
develops and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the
BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of
responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico.
NERC is the Electric Reliability Organization (ERO) for North America, subject to oversight by the Federal Energy
Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users,
owners, and operators of the BPS, which serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and
corresponding table below.
The North American BPS is divided into eight RE boundaries. The highlighted areas denote 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
SPP RE
Southwest Power Pool Regional Entity
Texas RE Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Supplemental GMD Event Description | October 2017
iii
Introduction
Background
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance (GMD)
Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated with
TPL‐007‐1, which was approved by the FERC Order No. 830 in September 2016. The benchmark GMD
event is derived from spatially‐averaged geoelectric field values to address potential wide‐area effects
that could be caused by a severe 1‐in‐100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event described in
this white paper, is used by entities to evaluate localized enhancements of geomagnetic field during a
severe GMD event that "could potentially affect the reliable operation of the Bulk‐Power System."2
Localized enhancements of geomagnetic field can result in geoelectric field values above the spatially‐
averaged benchmark in a local area.
The purpose of the supplemental GMD event description is to provide a defined event for assessing system
performance for a GMD event which includes a local enhancement of the geomagnetic field. In addition to varying
with time, geomagnetic fields can be spatially non‐uniform with higher and lower strengths across a region. This
spatial non‐uniformity has been observed in a number of GMD events, so localized enhancement of field strength
above the average value is considered. The supplemental GMD event defines the geomagnetic and geoelectric
field values used to compute geomagnetically‐induced current (GIC) flows for a supplemental GMD Vulnerability
Assessment.
General Characteristics
The supplemental GMD event described herein takes into consideration observed characteristics of a local
geomagnetic field enhancement, recognizing that the science and understanding of these events is evolving.
Based on observations and initial assessments, the characteristics of local enhancements include:
Geographic area – The extent of local enhancements is on the order of 100km in North‐South (latitude)
direction but longer in East‐West (longitude) direction. Further description of the geographic area is
provided later in the white paper.
Amplitude – The amplitude of the resulting geoelectric field is significantly higher than the geoelectric
field that is calculated in the spatially‐averaged Benchmark GMD event.
Duration – The local enhancement in the geomagnetic field occurs over a time period of two to five
minutes.
Geoelectric field waveform – The supplemental GMD event waveform is the benchmark GMD event
waveform with the addition of a local enhancement. The added local enhancement has amplitude and
duration characteristics described above. The geoelectric field waveform has a strong influence on the
hot spot heating of transformer windings and structural parts since thermal time constants of the
transformer and time to peak of storm maxima are both on the order of minutes. The frequency content
of the rate of change of the magnetic field (dB/dt) is a function of the waveform, which in turn has a direct
effect on the geoelectric field since the earth response to dB/dt is frequency‐dependent. As with the
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM 15‐11 on June 28, 2016.
2 See FERC Order No. 830, P. 47. In Order 830, FERC directed NERC to develop modifications to the benchmark GMD event, included in TPL‐
007‐1, such that assessments would not be based solely on spatially averaged data.
NERC | Supplemental GMD Event Description | October 2017
iv
Introduction
benchmark GMD event, the supplemental GMD event waveform is based on magnetic field data recorded
by the Natural Resources Canada (NRCan) Ottawa (OTT) geomagnetic observatory during the March 13‐
14, 1989 event. This GMD event data was selected because analysis of recorded events indicates that the
OTT observatory data for this period provides conservative results when performing thermal assessments
of power transformers.3
3
See Benchmark Geomagnetic Disturbance Event Description white paper, page 5 and Appendix I.
NERC | Supplemental GMD Event Description| October 2017
v
Supplemental GMD Event Description
Severe GMD events are high‐impact, low‐frequency (HILF) events [1]; thus, GMD events used in system planning
should consider the probability that the event will occur, as well as the impact or consequences of such an event.
The supplemental GMD event is composed of the following elements: 1) a reference peak geoelectric field
amplitude (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.
Supplemental GMD Event Geoelectric Field Amplitude
The supplemental GMD event field amplitude was determined through statistical analysis using the plane wave
method [2]‐[9] of geomagnetic field measurements from geomagnetic observatories in northern Europe [10] and
the North American (i.e., Québec) reference earth model shown in Table 1 [11], supplemented by data from
Greenland, Denmark and United States (i.e., Alaska). For details of the statistical considerations, see Appendix I.
The Québec earth model is generally resistive and the geological structure is relatively well understood.
Table 1: Reference Earth Model (Québec)
Thickness (km)
Resistivity (Ω‐m)
15
20,000
10
200
125
1,000
200
100
∞
3
The statistical analysis (see Appendix I) resulted in conservative peak geoelectric field amplitude of approximately
12 V/km. For steady‐state GIC and load flow analysis, the direction of the geoelectric field is assumed to be variable
meaning that it can be in any direction (Eastward, Northward, or a vectorial combination thereof).
The regional geoelectric field peak amplitude, Epeak, to be used in calculating GIC in the GIC system model can be
obtained from the reference value of 12 V/km using the following relationship
12
⁄
(1)
where α is the scaling factor to account for local geomagnetic latitude, and βS is a scaling factor for the
supplemental GMD event to account for the local earth conductivity structure (see Appendix II).
Supplemental Geomagnetic Field Waveform
The supplemental geomagnetic field waveform is the benchmark geomagnetic field waveform with the addition
of a local enhancement. Both the benchmark and supplemental geomagnetic field waveforms are used to
calculate the GIC time series, GIC(t), required for transformer thermal impact assessments. The supplemental
waveform includes a local enhancement, inserted at UT 1:18 March 14, 1989 in Figure 1 below. This time
corresponds to the largest calculated geoelectric fields during the benchmark GMD event. The amplitude of the
local enhancement is based on a statistical analysis of a number of GMD events, discussed in Appendix I. The
duration of the enhancement is based on the characteristics of observed localized enhancements as discussed in
Appendix I.
NERC | Supplemental GMD Event Description | October 2017
1
Supplemental GMD Event Description
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55; therefore, the amplitude of the
geomagnetic field measurement data with a local enhancement was scaled up to the 60 reference geomagnetic
latitude (see Figure 1) such that the resulting peak geoelectric field amplitude computed using the reference earth
model was 12 V/km (see Figure 2). Sampling rate for the geomagnetic field waveform is 10 seconds.
Eastward By
Northward Bx
Figure 1: Supplemental Geomagnetic Field Waveform
Red Bx (Northward), Blue By (Eastward), Referenced to pre-event quiet conditions
Figure 2: Supplemental Geoelectric Field Waveform
Red Ey (Eastward) and Blue Ex (Northward)
NERC | Supplemental GMD Event Description| October 2017
2
Appendix I – Technical Considerations
The following sections describe the technical justification of the assumptions that were made in the development
of the supplemental GMD event.
Statistical Considerations
The peak geoelectric field amplitude of the supplemental GMD event was determined through statistical analysis
of modern 10‐second geomagnetic field data and corresponding calculated geoelectric field amplitudes. The
objective of the analysis was to estimate the geoelectric field amplitude that is associated with a 1 in 100 year
frequency of occurrence. The same data set and similar statistical techniques were used in determining the peak
geoelectric field amplitude of the benchmark GMD event, including extreme value analysis discussed in the
following section.4 The fundamental difference in the supplemental GMD event amplitude is that it is based on
observations taken at each individual station (i.e., localized measurements), in contrast with the spatially averaged
geoelectric fields used in the Benchmark Geomagnetic Disturbance Event Description white paper.5
Extreme Value Analysis
The objective of extreme value analysis is to describe the behavior of a stochastic process at extreme deviations
from the median. In general, the intent is to quantify the probability of an event more extreme than any previously
observed. In particular, we are concerned with estimating the 95% confidence interval of the maximum
geoelectric field amplitude to be expected within a 100‐year return period.6
The data set consists of 23 years of daily maximum geoelectric field amplitudes derived from individual stations7
in the IMAGE magnetometer chain, using the Québec earth model as a reference. Figure I‐1 shows a scatter plot
of geoelectric field amplitudes that exceed 2 V/km across the IMAGE stations. The plot indicates that there is
seasonality in extreme observations associated with the 11‐year solar cycle.
4 See Benchmark Geomagnetic Disturbance Event Description white paper, Appendix I, pages 8‐13.
5 Averaging the geoelectric field values of stations in geographic groups is referred to as spatial averaging in the Benchmark Geomagnetic
Disturbance Event Description. Spatial averaging was used to characterize GMD events over a geographic area relevant to the
interconnected transmission system for purposes of assessing area effects such as voltage collapse and widespread equipment risk. See
Benchmark Geomagnetic Disturbance Event Description white paper, Appendix I, pages 9‐10.
6 A 95 percent confidence interval means that, if repeated samples were obtained, the return level would lie within the confidence interval
for 95 percent of the samples.
7 US – https://geomag.usgs.gov/; Canada – http://geomag.nrcan.gc.ca/lab/default‐en.php.
NERC | Supplemental GMD Event Description | October 2017
3
Appendix I – Technical Considerations
Figure I-1: Scatter Plot of Geoelectric Fields that Exceed a 2 V/km Threshold
Data source [11]: IMAGE magnetometer chain from 1993-2015.
Several statistical methods can be used to conduct extreme value analysis. The most commonly applied include:
Generalized Extreme Value (GEV), Point Over Threshold (POT), R‐Largest, and Point Process (PP). In general, all
methods assume independent and identically distributed (iid) data [12].
Table I‐1 shows a summary of the estimated parameters and return levels obtained from different statistical
methods. The parameters were estimated using the Maximum Likelihood Estimator (MLE). Since the distribution
parameters do not have an intuitive interpretation, the expected geoelectric field amplitude for a 100‐year return
period is also included in Table I‐1. The 95% confidence interval of the 100‐year return level was calculated using
the delta method and the profile likelihood. The delta method relies on the Gaussian approximation to the
distribution of the MLE; this approximation can be poor for long return periods. In general, the profile likelihood
provides a better description of the return level.
NERC | Supplemental GMD Event Description| October 2017
4
Appendix I – Technical Considerations
Table I-1: Extreme Value Analysis
100 Year Return Level
Mean
[V/km]
95% CI
Delta
[V/km]
95% CI
PLikelihood
[V/km]
H0: ξ=0
p = 0.66
6.9
[4.3, 8.2]
[5.2, 11.4]
β0= 2.964
(0.151)
β1=0.582
(0.155)
σ=0.627
(0.114)
ξ=0.09
(0.183)
H0: β1=0
p = 0.00
H0: ξ=0
p = 0.6
7.1
[4, 10.2]
[5.5, 18]
σ=0.592
(0.074)
ξ=0.077
(0.093)
6.9
[4.5, 9.4]
[5.4, 11.9]
β0=0.58
(0.073)
β1=0.107
(0.082)
ξ=0.037
(0.097)
H0: B1=0
p = 0.2
7
[4.6, 9.3]
[5.5, 11.7]
Statistical Model
Estimated
Parameters
Hypothesis
Testing
(1) GEV
µ=2.976
(0.193)
σ=0.829
(0.1357)
ξ=‐0.0655
(0.1446)
(2) GEV,
reparametrization
sin
(3) POT, threshold=2
V/km
3 day decluster.
143 observations >
2V/km.
(4) POT, threshold=2V/km
reparametrization,
sin
Statistical model (1) in Table I‐1 is the traditional GEV estimation using blocks of one year maxima; i.e., only 23
data points are used in the estimation. The mean expected amplitude of the geoelectric field for a 100‐year return
level is approximately 7 V/km. Since GEV works with blocks of maxima, it is typically regarded as a wasteful
approach.
NERC | Supplemental GMD Event Description| October 2017
5
Appendix I – Technical Considerations
As discussed previously, GEV assumes that the data is iid. Based on the scatter plot shown in Figure I‐1, the iid
statistical assumption is not warranted by the data. Statistical model (2) in Table I‐1 is a reparametrization of the
GEV distribution contemplating the 11‐year seasonality in the mean,
1
sin
where β0 represents the offset in the mean, β1 describes the 11‐year seasonality, T is the period (11 years), and φ
is a constant phase shift.
A likelihood ratio test is used to test the hypothesis that β1 is zero. The null hypothesis, H0: β1=0, is rejected with
a p‐value of 0.0032; as expected, the 11‐year seasonality has explanatory power. The blocks of maxima during the
solar minimum are better represented in the reparametrized GEV. The mean return level is still 7 V/km, but the
confidence interval is wider, [5.5, 18] V/km for the profile likelihood (calculated at solar maximum).
Statistical model (3) in Table I‐1 is the traditional POT estimation using a threshold u of 2 V/km; the data was
declustered using a 1‐day run. The data set consists of normalized excesses over a threshold, and therefore, the
sample size for POT is increased if more than one extreme observation per year is available (in the GEV approach,
only the maximum observation over the year was taken; in the POT method, a single year can have multiple
observations over the threshold). The selection of the threshold u is a compromise between bias and variance.
The asymptotic basis of the model relies on a high threshold; too low a threshold will likely lead to bias. On the
other hand, too high a threshold will reduce the sample size and result in high variance. A threshold of 2V/km was
determined to be a good choice, giving rise to 143 observations above the threshold.
The mean return level for statistical model (3), ~7 V/km, is consistent with the GEV estimates. However, due to
the larger sample size the POT method is more efficient rendering a confidence interval of [5.4, 11.9] V/km for the
profile likelihood method.
In an attempt to cope with potential heteroskedasticity in the data, a reparametrization of POT is proposed in
statistical model (4) in Table I‐1,
sin
where α0 represents the offset in the standard deviation, α1 describes the 11‐year seasonality, T is the period
(365.25 ∙ 11), and φ is a constant phase shift.
The parameter α1 is not statistically significant; the null hypothesis, H0: α1=0, is not rejected with a p‐value of 0.2.
The proposed reparametrization does not have explanatory power, and consequently, the mean return level 7
V/km and confidence intervals remain virtually unchanged [5.5, 11.7]. As a final remark, it is emphasized that the
confidence interval obtained using the profile likelihood is preferred over the delta method.
Figure I‐2 shows the profile likelihood of the 100‐year return level of statistical model (3). Note that the profile
likelihood is highly asymmetric with a positive skew, rendering a larger upper limit for the confidence interval.
Recall that the delta method assumes a normal distribution for the MLEs, and therefore, the confidence interval
is symmetric around the mean.
NERC | Supplemental GMD Event Description| October 2017
6
Profile Likelihood
Appendix I – Technical Considerations
Figure I-2: Profile Likelihood for 100-year Return Level for Statistical Model (3)
To conclude, the traditional GEV (1) is misspecified; the statistical assumptions (i.e., iid) are not warranted by the
data. The model was reparametrized to cope with seasonality in the data. Statistical models (3) and (4) better
utilize the available extreme measurements and they are therefore preferred over statistical model (2). A
geoelectric field amplitude of 12 V/km is selected for the supplemental GMD event to represent the upper limit
of the 95 percent confidence interval for a 100‐year return interval.
Spatial Considerations
The spatial structure of high‐latitude geomagnetic fields can be very complex during strong geomagnetic storm
events [13]‐[14]. One reflection of this spatial complexity is localized geomagnetic field enhancements (local
enhancements) that result in high amplitude geoelectric fields in regions of a few hundred kilometers. Figure I‐3
illustrates this spatial complexity of the storm‐time geoelectric fields.8 In areas indicated by the bright red location,
the geoelectric field can be substantially larger than at neighboring locations. These enhancements are primarily
the result of external (geomagnetic field) conditions, and not local geological factors such as coastal effects.9
8 Figure I‐3 is for illustration purposes only, and is not meant to suggest that a particular area is more likely to experience a localized
enhanced geoelectric field. The depiction is not to scale.
9 Localized externally‐driven geomagnetic phenomena should not be confused with localized geoelectric field enhancements due to
complex electromagnetic response of the ground to external excitation. Complex 3D geological conditions such as those at coastal regions
can lead to localized geoelectric field enhancements but those are not considered here.
NERC | Supplemental GMD Event Description| October 2017
7
Appendix I – Technical Considerations
Figure I-3: Illustration of the Spatial Scale between Localized Enhancements and Larger
Spatial Scale Amplitudes of Geoelectric Field during a Strong Geomagnetic Storm
In this figure, the red rectangle illustrates a spatially localized field enhancement.
The supplemental GMD event is designed to address local effects caused by a severe GMD event, such as increased
var absorption and voltage depressions.
A number of GMD events were analyzed to identify the basic characteristics of local enhancements. Three (3)
solar storms studied and described below are:
•
•
•
March 13, 1989
October 29‐30, 2003
March 17, 2015
Four localized events within those storms were identified and analyzed. Geomagnetic field recordings were
collected for these storms and the geoelectric field was computed using the 1D plane wave method and the
reference Québec ground model. In each case, a local enhancement was correlated, generally oriented parallel to
the westward ionospheric electrojet associated with ongoing larger scale geomagnetic activity. (See Figures I‐4 –
I‐7 below).
NERC | Supplemental GMD Event Description| October 2017
8
Appendix I – Technical Considerations
Figure I-4: March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark
Figure I-5: October 29, 2003, at 06:47 UT, Narsarsuaq (NAQ), Greenland
NERC | Supplemental GMD Event Description| October 2017
9
Appendix I – Technical Considerations
Figure I-6: October 30, 2003, at 16:49UT, Hopen Island (HOP), Svalbard, Norway
Figure I-7: March 17, 2015, at 13:33 UT, Deadhorse, Alaska, USA
NERC | Supplemental GMD Event Description| October 2017
10
Appendix I – Technical Considerations
All of the above events were analyzed by reviewing the time series magnetic field data and transforming it to an
electric field and focusing on the time period of the spatially correlated local enhancement. There were apparent
similarities in the character of the local enhancements. The local enhancements occurred during peak periods of
geomagnetic activity and were distinguished by relatively brief excursions of rapid magnetic field variation. With
respect to time duration, the local enhancements generally occurred over a period of 2‐5 minutes. (See Figures I‐
8 – I‐11)
Figure I-8: Geoelectric field March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark
Figure I-9: Geoelectric field October 29, 2003, at 06:47 UT,
Narsarsuaq (NAQ), Greenland
NERC | Supplemental GMD Event Description| October 2017
11
Appendix I – Technical Considerations
Figure I-10: Geoelectric field October 30, 2003, at 16:49 UT,
Hopen Island (HOP), Norway
Figure I-11 – Geoelectric field March 17, 2015, at 13:33 UT, Deadhorse, Alaska, USA
Based on the above analysis and the previous work associated with the benchmark GMD event, it is reasonable
to incorporate a second (or supplemental) assessment into TPL‐007‐2 to account for the potential impact of a
local enhancement in both the network analysis and the transformer thermal assessment(s).
With respect to geographic area of the localized enhancement, the historical geomagnetic field data analyzed so
far provides some insight. Analysis suggests that the enhancements will occur in a relatively narrow band of
geomagnetic latitude (on the order of 100 km) and wider longitudinal width (on the order of 500 km) as a
consequence of the westward‐oriented structure of the source in the ionosphere.
NERC | Supplemental GMD Event Description| October 2017
12
Appendix I – Technical Considerations
Proposed TPL‐007‐2 provides flexibility for planners to determine how to apply the supplemental GMD event to
the planning area. Acceptable approaches include, but are not limited to:
Applying the peak geoelectric field for the supplemental GMD event (12 V/km scaled to the planning area)
over the entire planning area;
Applying a spatially limited (e.g., 100 km in North‐South direction and 500 km in East‐West direction)
geoelectric field enhancement (12 V/km scaled to the planning area) over a portion(s) of the system, and
applying the benchmark GMD event over the rest of the system.
Other methods to adjust the benchmark GMD event analysis for localized geoelectric field enhancement.
Given the current state of knowledge regarding the spatial extent of a local geomagnetic field enhancements,
upper geographic boundaries, such as the values used in the approaches above, are reasonable but are not
definitive.
Local Enhancement Waveform
The supplemental geomagnetic field waveform was derived by modifying the benchmark GMD event waveform
to emulate the observed events described above. The temporal location of the enhancement corresponds to the
time of the benchmark event with the highest geoelectric field. The local enhancement was constructed by scaling
linearly a 5‐minute portion of the benchmark geomagnetic field so that the peak geoelectric field is 12 V/km at a
geomagnetic latitude of 60° and reference earth model. Figure I‐12 shows the benchmark geomagnetic field and
Figure I‐13 shows the supplemental event geomagnetic field. Figure I‐14 expands the view into Bx, with and
without the local enhancement. Figure I‐15 is the corresponding expanded view of the geoelectric field magnitude
with and without the local enhancement.
Figure I-12: Benchmark Geomagnetic Field
Red Bx (Northward), Blue By (Eastward)
NERC | Supplemental GMD Event Description| October 2017
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Appendix I – Technical Considerations
Figure I-13: Supplemental Geomagnetic Field Waveform
Red Bx (Northward), Blue By (Eastward)
Figure I-14: Red Benchmark Bx and Blue Supplemental Bx (Northward) – Expanded View
NERC | Supplemental GMD Event Description| October 2017
14
Appendix I – Technical Considerations
Figure I-15: Magnitude of the Geoelectric Field
Benchmark Blue and Supplemental Red – Expanded View
Transformer Thermal Assessment
The local enhancement of the supplemental GMD event waveform can have a material impact on the temperature
rise (hot‐spot heating or metallic parts) even though the duration of the local enhancement is approximately five
minutes. Thermal assessments based on the supplemental GMD event can be performed using the same methods
employed for benchmark thermal assessments.10
10 See Transformer Thermal Impact Assessment white paper: http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐
Disturbance‐Mitigation.aspx.
NERC | Supplemental GMD Event Description| October 2017
15
Appendix II – Scaling the Supplemental GMD Event
The intensity of a GMD event depends on geographical considerations such as geomagnetic latitude and local
earth conductivity [2].11 Scaling factors for geomagnetic latitude take into consideration that the intensity of a
GMD event varies according to latitude‐based geographical location. Scaling factors for earth conductivity take
into account that the induced geoelectric field depends on earth conductivity, and that different parts of the
continent have different earth conductivity and deep earth structure.
Scaling the supplemental GMD event differs from the benchmark GMD event in two ways:
Epeak is 12 V/km instead of 8 V/km
Beta factors for scaling the geoelectric field based on earth conductivity are different (see Table II‐2)
More discussion, including example calculations, is contained in the Benchmark GMD Event Description white
paper.
Scaling the Geomagnetic Field
The supplemental GMD event is defined for geomagnetic latitude of 60 and it must be scaled to account for
regional differences based on geomagnetic latitude. To allow usage of the supplemental geomagnetic field
waveform in other locations, Table II‐1 summarizes the scaling factor α correlating peak geoelectric field to
geomagnetic latitude as illustrated in Figure II‐1 [3]. This scaling factor has been obtained from a large number
of global geomagnetic field observations of all major geomagnetic storms since the late 1980s [15]‐[17], and can
be approximated with the empirical expression in (II.1):
0.001
.
(II.1)
where L is the geomagnetic latitude in degrees and 0.1 1.0.
Figure II-1: Geomagnetic Latitude Lines in North America
11 Geomagnetic latitude is analogous to geographic latitude, except that bearing is in relation to the magnetic poles, as opposed to the
geographic poles. Geomagnetic phenomena are often best organized as a function of geomagnetic coordinates. Local earth conductivity
refers to the electrical characteristics to depths of hundreds of km down to the earth’s mantle. In general terms, lower ground conductivity
results in higher geoelectric field amplitudes.
NERC | Supplemental GMD Event Description | October 2017
16
Appendix II – Scaling the Supplemental GMD Event
Table II-1: Geomagnetic Field Scaling Factors
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 supplemental GMD event is defined for the reference Québec earth model provided in Table 1. This earth
model has been used in many peer‐reviewed technical articles [11, 15]. The peak geoelectric field depends on the
geomagnetic field waveform and the local earth conductivity. Ideally, the peak geoelectric field, Epeak, is obtained
by calculating the geoelectric field from the scaled geomagnetic field waveform using the plane wave method and
taking the maximum value of the resulting waveforms:
∗
⁄
⁄
|
∗
,
(II.2)
|
where,
*denotes convolution in the time domain,
z(t) is the impulse response for the earth surface impedance calculated from the laterally uniform or 1D
earth model,
BE(t), BN(t) are the scaled Eastward and Northward geomagnetic field waveforms, and
|EE(t), EN(t)| are the magnitudes of the calculated Eastward and Northward geoelectric field EE(t) and EN(t).
As noted previously, the response of the earth to B(t) (and dB/dt) is frequency dependent. Figure II‐2 shows the
magnitude of Z(ω) for the reference earth model.
NERC | Supplemental GMD Event Description| October 2017
17
Appendix II – Scaling the Supplemental GMD Event
Figure II-2: Magnitude of the Earth Surface Impedance for the Reference Earth Model
If a utility does not have the capability of calculating the waveform or time series for the geoelectric field, an earth
conductivity scaling factor βS can be obtained from Table II‐2. Using α and β, the peak geoelectric field Epeak for a
specific service territory shown in Figure II‐3 can be obtained using (II.3).
12
⁄
(II.3)
It should be noted that (II.3) is an approximation based on the following assumptions:
The earth models used to calculate Table II‐2 for the United States are from published information
available on the USGS website. These scaling factors are slightly lower than the ones in the benchmark
because the supplemental benchmark waveform has a higher frequency content at the time of the local
enhancement.
The models used to calculate Table II‐2 for Canada were obtained from NRCan and reflect the average
structure for large regions. When models are developed for sub‐regions, there will be variance (to a
greater or lesser degree) from the average model. For instance, detailed models for Ontario have been
developed by NRCan and consist of seven major sub‐regions.
The conductivity scaling factor βS is calculated as the quotient of the local geoelectric field peak amplitude
in a physiographic region with respect to the reference peak amplitude value of 12 V/km. Both geoelectric
field peak amplitudes are calculated using the supplemental geomagnetic field time series. If a different
geomagnetic field time series were used, the calculated scaling factors (β) would be different than the
values in Table II‐2 because the frequency content of storm maxima is, in principle, different for every
storm. If a utility has technically‐sound earth models for its service territory and sub‐regions thereof, then
the use of such earth models is preferable to estimate Epeak.
When a ground conductivity model is not available the planning entity should use the largest βs factor of
adjacent physiographic regions or a technically‐justified value.
NERC | Supplemental GMD Event Description| October 2017
18
Appendix II – Scaling the Supplemental GMD Event
Physiographic Regions of the Continental United States
Physiographic Regions of Canada
Figure II-3: Physiographic Regions of North America
NERC | Supplemental GMD Event Description| October 2017
19
Appendix II – Scaling the Supplemental GMD Event
Table II-2 Supplemental Geoelectric Field Scaling Factors
Earth model
Scaling Factor ()
AK1A
0.51
AK1B
0.51
AP1
0.30
AP2
0.78
BR1
0.22
CL1
0.73
CO1
0.25
CP1
0.77
CP2
0.86
FL1
0.73
CS1
0.37
IP1
0.90
IP2
0.25
IP3
0.90
IP4
0.35
NE1
0.77
PB1
0.55
PB2
0.39
PT1
1.19
SL1
0.49
SU1
0.90
BOU
0.24
FBK
0.56
PRU
0.22
BC
0.62
PRAIRIES
0.88
SHIELD
1.0
ATLANTIC
0.76
NERC | Supplemental GMD Event Description| October 2017
20
References
[1]
High‐Impact, Low‐Frequency Event Risk to the North American Bulk Power System, A Jointly‐
Commissioned Summary Report of the North American Reliability Corporation and the U.S.
Department of Energy’s November 2009 Workshop.
[2]
Application Guide: Computing Geomagnetically‐Induced Current in the Bulk‐Power System, NERC.
December 2013. http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20
Force%20GMDTF%202013/GIC%20Application%20Guide%202013_approved.pdf
[3]
Boteler, D. H.; Pirjola R. J.; Liu, L.; and Zheng, K.; “Geoelectric Fields Due to Small‐Scale and Large‐Scale
Source Currents.” IEEE Transactions on Power Delivery, Vol. 28, No. 1, January 2013, pp. 442‐449.
[4]
Boteler, D. H. “Geomagnetically Induced Currents: Present Knowledge and Future Research.” IEEE
Transactions on Power Delivery, Vol. 9, No. 1, January 1994, pp. 50‐58.
[5]
Boteler, D. H. “Modeling Geomagnetically Induced Currents Produced by Realistic and Uniform Electric
Fields.” IEEE Transactions on Power Delivery, Vol. 13, No. 4, January 1998, pp. 1303‐1308.
[6]
Gilbert, J. L.; Radasky, W. A.; and Savage, E. B. “A Technique for Calculating the Currents Induced by
Geomagnetic Storms on Large High Voltage Power Grids.” Electromagnetic Compatibility (EMC). 2012
IEEE International Symposium on.
[7]
How to Calculate Electric Fields to Determine Geomagnetically‐Induced Currents. EPRI, Palo Alto, CA:
2013. 3002002149.
[8]
Pirjola, R.; Pulkkinen, A.; and Viljanen, V. Statistics of extreme geomagnetically induced current events,
Space Weather, 6, S07001, doi:10.1029/2008SW000388, 2008.
[9]
Boteler, D. H. Assessment of geomagnetic hazard to power systems in Canada, Nat. Hazards, 23, 101–
120. 2001.
[10] Finnish Meteorological Institute’s IMAGE magnetometer chain data available at:
http://image.gsfc.nasa.gov/
[11] Boteler, D. H. and Pirjola, R. J. The complex‐image method for calculating the magnetic and electric
fields produced at the surface of the Earth by the auroral electrojet. Geophys. J. Int., 132(1), 31—40.
1998.
[12] Coles, S. An Introduction to Statistical Modelling of Extreme Values. Springer. 2001.
[13] Clarke, E.; Mckay, A.; Pulkkinen, A.; and Thomson, A. April 2000 geomagnetic storm: ionospheric
drivers of large geomagnetically induced currents. Annales Geophysicae, 21, 709‐717. 2003.
[14] Lindahl, S.; Pirjola, R. J.; Pulkkinen, A.; and Viljanen, A. Geomagnetic storm of 29–31 October 2003:
Geomagnetically induced currents and their relation to problems in the Swedish high‐voltage power
transmission system. Space Weather, 3, S08C03, doi:10.1029/2004SW000123. 2005.
[15] Beggan, C.; Bernabeu, E.; Eichner, J.; Pulkkinen, A.; and Thomson, A., Generation of 100‐year
geomagnetically induced current scenarios, Space Weather, Vol. 10, S04003,
doi:10.1029/2011SW000750. 2012.
NERC | Supplemental GMD Event Description | October 2017
21
References
[16] Crowley, G.; Ngwira, C.; Pulkkinen, A.; and Wilder, F. Extended study of extreme geoelectric field event
scenarios for geomagnetically induced current applications. Space Weather, Vol. 11, 121–131,
doi:10.1002/swe.20021. 2013.
[17] Dawson, E.; Reay, S.; and Thomson, A. Quantifying extreme behavior in geomagnetic activity. Space
Weather, 9, S10001, doi:10.1029/2011SW000696. 2011.
NERC | Supplemental GMD Event Description| October 2017
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Supplemental
Geomagnetic
Disturbance Event
Description
Project 2013-03 GMD Mitigation
JuneOctober 2017
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
General Characteristics .......................................................................................................................................... iv
Supplemental GMD Event Description ...................................................................................................................... 1
Supplemental GMD Event Geoelectric Field Amplitude ........................................................................................ 1
Supplemental Geomagnetic Field Waveform ........................................................................................................ 1
Appendix I – Technical Considerations ...................................................................................................................... 4
Statistical Considerations ....................................................................................................................................... 4
Extreme Value Analysis ...................................................................................................................................... 4
Spatial Considerations ........................................................................................................................................... 8
Local Enhancement Waveform ............................................................................................................................ 14
Transformer Thermal Assessment ....................................................................................................................... 16
Appendix II – Scaling the Supplemental GMD Event ............................................................................................... 17
Scaling the Geomagnetic Field ............................................................................................................................. 17
Scaling the Geoelectric Field ................................................................................................................................ 18
References ............................................................................................................................................................... 22
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
ii
Preface
The North American Electric Reliability Corporation (NERC) is a not‐for‐profit international regulatory authority
whose mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC
develops and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the
BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of
responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico.
NERC is the Electric Reliability Organization (ERO) for North America, subject to oversight by the Federal Energy
Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users,
owners, and operators of the BPS, which serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and
corresponding table below.
The North American BPS is divided into eight RE boundaries. The highlighted areas denote 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
SPP RE
Southwest Power Pool Regional Entity
Texas RE Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
iii
Introduction
Background
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance (GMD)
Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated with
TPL‐007‐1, which was approved by the Federal Energy Regulatory Commission (FERC) in Order No. 830 in
September 2016. The benchmark GMD event is derived from spatially‐averaged geoelectric field values
to address potential wide‐area effects that could be caused by a severe 1‐in‐100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event described in
this white paper, is used by entities to evaluate localized enhancements of geomagnetic field during a
severe GMD event that "could potentially affect the reliable operation of the Bulk‐Power System".."2
Localized enhancements of geomagnetic field can result in geoelectric field values above the spatially‐
averaged benchmark in a local area.
The purpose of the supplemental geomagnetic disturbance (GMD) event description is to provide a defined event
for assessing system performance for a GMD event which includes a local enhancement of the geomagnetic field.
In addition to varying with time, geomagnetic fields can be spatially non‐uniform with higher and lower strengths
across a region. This spatial non‐uniformity has been observed in a number of GMD events, so localized
enhancement of field strength above the average value is considered. The supplemental GMD event defines the
geomagnetic and geoelectric field values used to compute geomagnetically‐induced current (GIC) flows for a
supplemental GMD Vulnerability Assessment.
General Characteristics
The supplemental GMD event described herein takes into consideration observed characteristics of a local
geomagnetic field enhancement, recognizing that the science and understanding of these events is evolving.
Based on observations and initial assessments, the characteristics of local enhancements include:
Geographic area – The extent of local enhancements is on the order of 100km in North‐South (latitude)
direction but longer in East‐West (longitude) direction. Further description of the geographic area is
provided later in the white paper.
Amplitude – The amplitude of the resulting geoelectric field is significantly higher than the geoelectric
field that is calculated in the spatially‐averaged Benchmark GMD event.
Duration – The local enhancement in the geomagnetic field occurs over a time period of 2‐5two to five
minutes.
Geoelectric field waveform – The supplemental GMD event waveform is the benchmark GMD event
waveform with the addition of a local enhancement. The added local enhancement has amplitude and
duration characteristics described above. The geoelectric field waveform has a strong influence on the
hot spot heating of transformer windings and structural parts since thermal time constants of the
transformer and time to peak of storm maxima are both on the order of minutes. The frequency content
of the rate of change of the magnetic field (dB/dt) is a function of the waveform, which in turn has a direct
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM 15‐11 on June 28, 2016.
2 See FERC Order No. 830, P. 47.
On September 22, 2016In Order 830, FERC directed NERC to develop modifications to the benchmark
GMD event, included in TPL‐007‐1, such that assessments would not be based solely on spatially averaged data.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
iv
Introduction
effect on the geoelectric field since the earth response to dB/dt is frequency‐dependent. As with the
benchmark GMD event, the supplemental GMD event waveform is based on magnetic field data recorded
by the Natural Resources Canada (NRCan) Ottawa (OTT) geomagnetic observatory during the March 13‐
14, 1989 event. This GMD event data was selected because analysis of recorded events indicates that the
OTT observatory data for this period provides conservative results when performing thermal assessments
of power transformers.3
3
See Benchmark Geomagnetic Disturbance Event Description white paper, page 5 and Appendix I.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
v
Supplemental GMD Event Description
Severe geomagnetic disturbanceGMD events are high‐impact, low‐frequency (HILF) events [1]; thus, GMD events
used in system planning should consider the probability that the event will occur, as well as the impact or
consequences of such an event. The supplemental GMD event is composed of the following elements: 1) a
reference peak geoelectric field amplitude (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.
Supplemental GMD Event Geoelectric Field Amplitude
The supplemental GMD event field amplitude was determined through statistical analysis using the plane wave
method [2]‐[9] of geomagnetic field measurements from geomagnetic observatories in northern Europe [10] and
the North American (i.e., Québec) reference (Quebec) earth model shown in Table 1 [11], supplemented by data
from Greenland, Denmark and United States (i.e., Alaska.). For details of the statistical considerations, see
Appendix I. The QuebecQuébec earth model is generally resistive and the geological structure is relatively well
understood.
Table 1: Reference Earth Model (QuebecQuébec)
Thickness (km)
Resistivity (Ω‐m)
15
20,000
10
200
125
1,000
200
100
∞
3
The statistical analysis (see Appendix I) resulted in conservative peak geoelectric field amplitude of approximately
12 V/km. For steady‐state GIC and load flow analysis, the direction of the geoelectric field is assumed to be variable
meaning that it can be in any direction (Eastward, Northward, or a vectorial combination thereof).
The regional geoelectric field peak amplitude, Epeak, to be used in calculating GIC in the GIC system model can be
obtained from the reference value of 12 V/km using the following relationship
Epeak
12
(V/km)
⁄
(1)
where α is the scaling factor to account for local geomagnetic latitude, and βS is a scaling factor for the
supplemental GMD event to account for the local earth conductivity structure (see Appendix II).
Supplemental Geomagnetic Field Waveform
The supplemental geomagnetic field waveform is the benchmark geomagnetic field waveform with the addition
of a local enhancement. Both the benchmark and supplemental geomagnetic field waveforms are used to
calculate the GIC time series, GIC(t), required for transformer thermal impact assessments. The supplemental
waveform includes a local enhancement, inserted at UT 1:18 March 14, 1989 in Figure 1 below. This time
corresponds to the largest calculated geoelectric fields during the benchmark GMD event. The amplitude of the
local enhancement is based on a statistical analysis of a number of GMD events, discussed in Appendix I. The
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
Supplemental GMD Event Description
duration of the enhancement is based on the characteristics of observed localized enhancements as discussed in
Appendix I.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55; therefore, the amplitude of the
geomagnetic field measurement data with a local enhancement was scaled up to the 60 reference geomagnetic
latitude (see Figure 1) such that the resulting peak geoelectric field amplitude computed using the reference earth
model was 12 V/km (see Figure 2). Sampling rate for the geomagnetic field waveform is 10 seconds.
Eastward By
Northward Bx
Figure 1: Supplemental Geomagnetic Field Waveform
Red Bx (Northward), Blue By (Eastward), Referenced to pre-event quiet conditions
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
2
Supplemental GMD Event Description
Figure 2: Supplemental Geoelectric Field Waveform
Red Ey (Eastward) and Blue Ex (Northward)
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
3
Appendix I – Technical Considerations
The following sections describe the technical justification of the assumptions that were made in the development
of the supplemental GMD event.
Statistical Considerations
The peak geoelectric field amplitude of the supplemental GMD event was determined through statistical analysis
of modern 10‐second geomagnetic field data and corresponding calculated geoelectric field amplitudes. The
objective of the analysis was to estimate the geoelectric field amplitude that is associated with a 1 in 100 year
frequency of occurrence. The same data set and similar statistical techniques were used in determining the peak
geoelectric field amplitude of the benchmark GMD event, including extreme value analysis discussed in the
following section.4 The fundamental difference in the supplemental GMD event amplitude is that it is based on
observations taken at each individual station (i.e., localized measurements), in contrast with the spatially averaged
geoelectric fields used in the Benchmark Geomagnetic Disturbance Event Description white paper.5
Extreme Value Analysis
The objective of extreme value analysis is to describe the behavior of a stochastic process at extreme deviations
from the median. In general, the intent is to quantify the probability of an event more extreme than any previously
observed. In particular, we are concerned with estimating the 95% confidence interval of the maximum
geoelectric field amplitude to be expected within a 100‐year return period.6
The data set consists of 23 years of daily maximum geoelectric field amplitudes derived from individual stations7
in the IMAGE magnetometer chain, using the QuebecQuébec earth model as a reference. Figure I‐1 shows a
scatter plot of geoelectric field amplitudes that exceed 2 V/km across the IMAGE stations. The plot indicates that
there is seasonality in extreme observations associated with the 11‐year solar cycle.
4 See Benchmark Geomagnetic Disturbance Event Description white paper, Appendix I, pages 8‐13.
5 Averaging the geoelectric field values of stations in geographic groups is referred to as spatial averaging in the Benchmark Geomagnetic
Disturbance Event Description. Spatial averaging was used to characterize GMD events over a geographic area relevant to the
interconnected transmission system for purposes of assessing area effects such as voltage collapse and widespread equipment risk. See
Benchmark Geomagnetic Disturbance Event Description white paper, Appendix I, pages 9‐10.
6 A 95 percent confidence interval means that, if repeated samples were obtained, the return level would lie within the confidence interval
for 95 percent of the samples.
7 US – https://geomag.usgs.gov/; Canada – http://geomag.nrcan.gc.ca/lab/default‐en.php.
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
Appendix I – Technical Considerations
Figure I-1: Scatter Plot of Geoelectric Fields that Exceed a 2 V/km Threshold
Data source [11]: IMAGE magnetometer chain from 1993-2015.
Several statistical methods can be used to conduct extreme value analysis. The most commonly applied include:
Generalized Extreme Value (GEV), Point Over Threshold (POT), R‐Largest, and Point Process (PP). In general, all
methods assume independent and identically distributed (iid) data [12].
Table I‐1 shows a summary of the estimated parameters and return levels obtained from different statistical
methods. The parameters were estimated using the Maximum Likelihood Estimator (MLE). Since the distribution
parameters do not have an intuitive interpretation, the expected geoelectric field amplitude for a 100‐year return
period is also included in Table I‐1. The 95% confidence interval of the 100‐year return level was calculated using
the delta method and the profile likelihood. The delta method relies on the Gaussian approximation to the
distribution of the MLE; this approximation can be poor for long return periods. In general, the profile likelihood
provides a better description of the return level.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
5
01
t
sin
T
Appendix I – Technical Considerations
Table I-1: Extreme Value Analysis
100 Year Return Level
Mean
[V/km]
95% CI
Delta
[V/km]
95% CI
PLikelihood
[V/km]
H0: ξ=0
p = 0.66
6.9
[4.3, 8.2]
[5.2, 11.4]
β0= 2.964
(0.151)
β1=0.582
(0.155)
σ=0.627
(0.114)
ξ=0.09
(0.183)
H0: β1=0
p = 0.00
H0: ξ=0
p = 0.6
7.1
[4, 10.2]
[5.5, 18]
σ=0.592
(0.074)
ξ=0.077
(0.093)
6.9
[4.5, 9.4]
[5.4, 11.9]
β0=0.58
(0.073)
β1=0.107
(0.082)
ξ=0.037
(0.097)
H0: B1=0
p = 0.2
7
[4.6, 9.3]
[5.5, 11.7]
Statistical Model
Estimated
Parameters
Hypothesis
Testing
(1) GEV
µ=2.976
(0.193)
σ=0.829
(0.1357)
ξ=‐0.0655
(0.1446)
(2) GEV,
reparametrization
sin
(3) POT, threshold=2
V/km
3 day decluster.
143 observations >
2V/km.
(4) POT, threshold=2V/km
reparametrization,
sin
Statistical model (1) in Table I‐1 is the traditional GEV estimation using blocks of 1one year maxima; i.e., only 23
data points are used in the estimation. The mean expected amplitude of the geoelectric field for a 100‐year return
level is approximately 7 V/km. Since GEV works with blocks of maxima, it is typically regarded as a wasteful
approach.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
6
01
t
sin
T
Appendix I – Technical Considerations
As discussed previously, GEV assumes that the data is iid. Based on the scatter plot shown in Figure I‐1, the iid
statistical assumption is not warranted by the data. Statistical model (2) in Table I‐1 is a reparametrization of the
GEV distribution contemplating the 11‐year seasonality in the mean,
1
sin
where β0 represents the offset in the mean, β1 describes the 11‐year seasonality, T is the period (11 years), and φ
is a constant phase shift.
A likelihood ratio test is used to test the hypothesis that β1 is zero. The null hypothesis, H0: β1=0, is rejected with
a p‐value of 0.0032; as expected, the 11‐year seasonality has explanatory power. The blocks of maxima during the
solar minimum are better represented in the reparametrized GEV. The mean return level is still 7 V/km, but the
confidence interval is wider, [5.5, 18] V/km for the profile likelihood (calculated at solar maximum).
Statistical model (3) in Table I‐1 is the traditional POT estimation using a threshold u of 2 V/km; the data was
declustered using a 1‐day run. The data set consists of normalized excesses over a threshold, and therefore, the
sample size for POT is increased if more than one extreme observation per year is available (in the GEV approach,
only the maximum observation over the year was taken; in the POT method, a single year can have multiple
observations over the threshold). The selection of the threshold u is a compromise between bias and variance.
The asymptotic basis of the model relies on a high threshold; too low a threshold will likely lead to bias. On the
other hand, too high a threshold will reduce the sample size and result in high variance. A threshold of 2V/km was
determined to be a good choice, giving rise to 143 observations above the threshold.
The mean return level for statistical model (3), ~7 V/km, is consistent with the GEV estimates. However, due to
the larger sample size the POT method is more efficient rendering a confidence interval of [5.4, 11.9] V/km for the
profile likelihood method.
In an attempt to cope with potential heteroskedasticity in the data, a reparametrization of POT is proposed in
statistical model (4) in Table I‐1,
sin
where α0 represents the offset in the standard deviation, α1 describes the 11‐year seasonality, T is the period
(365.25 ∙ 11), and φ is a constant phase shift.
The parameter α1 is not statistically significant; the null hypothesis, H0: α1=0, is not rejected with a p‐value of 0.2.
The proposed reparametrization does not have explanatory power, and consequently, the mean return level 7
V/km and confidence intervals remain virtually unchanged [5.5, 11.7]. As a final remark, it is emphasized that the
confidence interval obtained using the profile likelihood is preferred over the delta method.
Figure I‐2 shows the profile likelihood of the 100‐year return level of statistical model (3). Note that the profile
likelihood is highly asymmetric with a positive skew, rendering a larger upper limit for the confidence interval.
Recall that the delta method assumes a normal distribution for the MLEs, and therefore, the confidence interval
is symmetric around the mean.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
7
Profile Likelihood
Appendix I – Technical Considerations
Figure I-2: Profile Likelihood for 100-year Return Level for Statistical Model (3)
To conclude, the traditional GEV (1) is misspecified; the statistical assumptions (i.e., iid) are not warranted by the
data. The model was reparametrized to cope with seasonality in the data. Statistical models (3) and (4) better
utilize the available extreme measurements and they are therefore preferred over statistical model (2). A
geoelectric field amplitude of 12 V/km is selected for the supplemental GMD event to represent the upper limit
of the 95 percent confidence interval for a 100‐year return interval.
Spatial Considerations
The spatial structure of high‐latitude geomagnetic fields can be very complex during strong geomagnetic storm
events [13]‐[14]. One reflection of this spatial complexity is localized geomagnetic field enhancements (local
enhancements) that result in high amplitude geoelectric fields in regions of a few hundred kilometers. Figure I‐3
illustrates this spatial complexity of the storm‐time geoelectric fields.8 In areas indicated by the bright red location,
the geoelectric field can be substantially larger than at neighboring locations. These enhancements are primarily
the result of external (geomagnetic field) conditions, and not local geological factors such as coastal effects.9
8 Figure I‐3 is for illustration purposes only, and is not meant to suggest that a particular area is more likely to experience a localized
enhanced geoelectric field. The depiction is not to scale.
9 Localized externally‐driven geomagnetic phenomena should not be confused with localized geoelectric field enhancements due to
complex electromagnetic response of the ground to external excitation. Complex 3D geological conditions such as those at coastal regions
can lead to localized geoelectric field enhancements but those are not considered here.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
8
Appendix I – Technical Considerations
Figure I-3: Illustration of the Spatial Scale between Localized Enhancements and Larger
Spatial Scale Amplitudes of Geoelectric Field during a Strong Geomagnetic Storm
In this figure, the red rectangle illustrates a spatially localized field enhancement.
The supplemental GMD event is designed to address local effects caused by a severe GMD event, such as increased
var absorption and voltage depressions.
A number of GMD events were analyzed to identify the basic characteristics of local enhancements. Three (3)
solar storms studied and described below are:
•
•
•
March 13, 1989
• October 29‐30, 2003
• March 17, 2015
Four localized events within those storms were identified and analyzed. Geomagnetic field recordings were
collected for these storms and the geoelectric field was computed using the 1D plane wave method and the
reference QuebecQuébec ground model. In each case, a local enhancement was correlated, generally oriented
parallel to the westward ionospheric electrojet associated with ongoing larger scale geomagnetic activity. (See
Figures I‐4 ̶ – I‐7 below)).
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
9
Appendix I – Technical Considerations
Figure I-4: March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark
Figure I-5: October 29, 2003, at 06:47 UT, Narsarsuaq (NAQ), Greenland
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix I – Technical Considerations
Figure I-6: October 30, 2003, at 16:49UT, Hopen Island (HOP), Svalbard, Norway
Figure I-7: March 17, 2015, at 13:33 UT, Deadhorse, Alaska, USA
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
11
Appendix I – Technical Considerations
All of the above events were analyzed by reviewing the time series magnetic field data and transforming it to an
electric field and focusing on the time period of the spatially correlated local enhancement. There were apparent
similarities in the character of the local enhancements. The local enhancements occurred during peak periods of
geomagnetic activity and were distinguished by relatively brief excursions of rapid magnetic field variation. With
respect to time duration, the local enhancements generally occurred over a period of 2‐5 minutes. (See Figures I‐
8 ̶ – I‐11)
Figure I-8: Geoelectric field March 13, 1989, at 21:44 UT, Brorfelde (BFE), Denmark
Figure I-9: Geoelectric field October 29, 2003, at 06:47 UT,
Narsarsuaq (NAQ), Greenland
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
12
Appendix I – Technical Considerations
Figure I-10: Geoelectric field October 30, 2003, at 16:49 UT,
Hopen Island (HOP), Norway
Figure I-11 – Geoelectric field March 17, 2015, at 13:33 UT, Deadhorse, Alaska, USA
Based on the above analysis and the previous work associated with the benchmark GMD event, it is reasonable
to incorporate a second (or supplemental) assessment into TPL‐007‐2 to account for the potential impact of a
local enhancement in both the network analysis and the transformer thermal assessment(s).
With respect to geographic area of the localized enhancement, the historical geomagnetic field data analyzed so
far provides some insight. Analysis suggests that the enhancements will occur in a relatively narrow band of
geomagnetic latitude (on the order of 100 km) and wider longitudinal width (on the order of 500 km) as a
consequence of the westward‐oriented structure of the source in the ionosphere.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix I – Technical Considerations
Proposed TPL‐007‐2 provides flexibility for planners to determine how to apply the supplemental GMD event to
the planning area. Acceptable approaches include, but are not limited to:
ApplyApplying the peak geoelectric field for the supplemental GMD event (12 V/km scaled to the planning
area) over the entire planning area;
ApplyApplying a spatially limited (e.g., 100 km in North‐South direction and 500 km in East‐West direction)
geoelectric field enhancement (12 V/km scaled to the planning area) over a portion(s) of the system, and
applyapplying the benchmark GMD event over the rest of the system.
Other methods to adjust the benchmark GMD event analysis for localized geoelectric field enhancement.
Given the current state of knowledge regarding the spatial extent of a local geomagnetic field enhancements,
upper geographic boundaries, such as the values used in the approaches above, are reasonable but are not
definitive.
Local Enhancement Waveform
The supplemental geomagnetic field waveform was derived by modifying the benchmark GMD event waveform
to emulate the observed events described above. The temporal location of the enhancement corresponds to the
time of the benchmark event with the highest geoelectric field. The local enhancement was constructed by scaling
linearly a 5‐minute portion of the benchmark geomagnetic field so that the peak geoelectric field is 12 V/km at a
geomagnetic latitude of 60° and reference earth model. Figure I‐12 shows the benchmark geomagnetic field and
Figure I‐13 shows the supplemental event geomagnetic field. Figure I‐14 expands the view into Bx, with and
without the local enhancement. Figure I‐15 is the corresponding expanded view of the geoelectric field magnitude
with and without the local enhancement.
Figure I-12: Benchmark Geomagnetic Field
Red Bx (Northward), Blue By (Eastward)
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14
Appendix I – Technical Considerations
Figure I-13: Supplemental Geomagnetic Field Waveform
Red Bx (Northward), Blue By (Eastward)
Figure I-14: Red Benchmark Bx and Blue Supplemental Bx (Northward) – Expanded View
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix I – Technical Considerations
Figure I-15: Magnitude of the Geoelectric Field
Benchmark Blue and Supplemental Red – Expanded View
Transformer Thermal Assessment
The local enhancement of the supplemental GMD event waveform can have a material impact on the temperature
rise (hot‐spot heating or metallic parts) even though the duration of the local enhancement is approximately 5five
minutes. Thermal assessments based on the supplemental GMD event can be performed using the same methods
employed for benchmark thermal assessments.10
10 See Transformer Thermal Impact Assessment white paper: 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.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix II – Scaling the Supplemental GMD Event
The intensity of a GMD event depends on geographical considerations such as geomagnetic latitude and local
earth conductivity [2].11 Scaling factors for geomagnetic latitude take into consideration that the intensity of a
GMD event varies according to latitude‐based geographical location. Scaling factors for earth conductivity take
into account that the induced geoelectric field depends on earth conductivity, and that different parts of the
continent have different earth conductivity and deep earth structure.
Scaling the supplemental GMD event differs from the benchmark GMD event in two ways:
Epeak is 12 V/km instead of 8 V/km
Beta factors for scaling the geoelectric field based on earth conductivity are different (see Table II‐2)
More discussion, including example calculations, is contained in the Benchmark GMD Event Description white
paper.
Scaling the Geomagnetic Field
The supplemental GMD event is defined for geomagnetic latitude of 60 and it must be scaled to account for
regional differences based on geomagnetic latitude. To allow usage of the supplemental geomagnetic field
waveform in other locations, Table II‐1 summarizes the scaling factor α correlating peak geoelectric field to
geomagnetic latitude as describedillustrated in Figure II‐1 [3]. This scaling factor has been obtained from a large
number of global geomagnetic field observations of all major geomagnetic storms since the late 1980s [15]‐[2717],
and can be approximated with the empirical expression in (II.1)):
0.001
.
(II.1)
where L is the geomagnetic latitude in degrees and 0.1 1.0.
Figure II-1: Geomagnetic Latitude Lines in North America
11 Geomagnetic latitude is analogous to geographic latitude, except that bearing is in relation to the magnetic poles, as opposed to the
geographic poles. Geomagnetic phenomena are often best organized as a function of geomagnetic coordinates. Local earth conductivity
refers to the electrical characteristics to depths of hundreds of km down to the earth’s mantle. In general terms, lower ground conductivity
results in higher geoelectric field amplitudes.
NERC | Supplemental GMD Event Description (DRAFT)| June 2017
Appendix II – Scaling the Supplemental GMD Event
Table II-1: Geomagnetic Field Scaling Factors
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 supplemental GMD event is defined for the reference QuebecQuébec earth model provided in Table 1. This
earth model has been used in many peer‐reviewed technical articles [11, 15]. The peak geoelectric field depends
on the geomagnetic field waveform and the local earth conductivity. Ideally, the peak geoelectric field, Epeak, is
obtained by calculating the geoelectric field from the scaled geomagnetic field waveform using the plane wave
method and taking the maximum value of the resulting waveforms:
∗
⁄
⁄
|
∗
,
(II.2)
|
where,
*denotes convolution in the time domain,
z(t) is the impulse response for the earth surface impedance calculated from the laterally uniform or 1D
earth model,
BE(t), BN(t) are the scaled Eastward and Northward geomagnetic field waveforms, and
|EE(t), EN(t)| are the magnitudes of the calculated Eastward and Northward geoelectric field EE(t) and EN(t).
As noted previously, the response of the earth to B(t) (and dB/dt) is frequency dependent. Figure II‐2 shows the
magnitude of Z(ω) for the reference earth model.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix II – Scaling the Supplemental GMD Event
Figure II-2: Magnitude of the Earth Surface Impedance for the Reference Earth Model
If a utility does not have the capability of calculating the waveform or time series for the geoelectric field, an earth
conductivity scaling factor βS can be obtained from Table II‐2. Using α and β, the peak geoelectric field Epeak for a
specific service territory shown in Figure II‐3 can be obtained using (II.3).
12
⁄
(II.3)
It should be noted that (II.3) is an approximation based on the following assumptions:
The earth models used to calculate Table II‐2 for the United States are from published information
available on the USGS website. These scaling factors are slightly lower than the ones in the benchmark
because the supplemental benchmark waveform has a higher frequency content at the time of the local
enhancement.
The models used to calculate Table II‐2 for Canada were obtained from NRCan and reflect the average
structure for large regions. When models are developed for sub‐regions, there will be variance (to a
greater or lesser degree) from the average model. For instance, detailed models for Ontario have been
developed by NRCan and consist of seven major sub‐regions.
The conductivity scaling factor βS is calculated as the quotient of the local geoelectric field peak amplitude
in a physiographic region with respect to the reference peak amplitude value of 12 V/km. Both geoelectric
field peak amplitudes are calculated using the supplemental geomagnetic field time series. If a different
geomagnetic field time series were used, the calculated scaling factors (β) would be different than the
values in Table II‐2 because the frequency content of storm maxima is, in principle, different for every
storm. If a utility has technically‐sound earth models for its service territory and sub‐regions thereof, then
the use of such earth models is preferable to estimate Epeak.
When a ground conductivity model is not available the planning entity should use the largest βs factor of
adjacent physiographic regions or a technically‐justified value.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix II – Scaling the Supplemental GMD Event
Physiographic Regions of the Continental United States
Physiographic Regions of Canada
Figure II-3: Physiographic Regions of North America
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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Appendix II – Scaling the Supplemental GMD Event
Table II-2 Supplemental Geoelectric Field Scaling Factors
Earth model
Scaling Factor ()
AK1A
0.51
AK1B
0.51
AP1
0.30
AP2
0.78
BR1
0.22
CL1
0.73
CO1
0.25
CP1
0.77
CP2
0.86
FL1
0.73
CS1
0.37
IP1
0.90
IP2
0.25
IP3
0.90
IP4
0.35
NE1
0.77
PB1
0.55
PB2
0.39
PT1
1.19
SL1
0.49
SU1
0.90
BOU
0.24
FBK
0.56
PRU
0.22
BC
0.62
PRAIRIES
0.88
SHIELD
1.0
ATLANTIC
0.76
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
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References
[1]
High‐Impact, Low‐Frequency Event Risk to the North American Bulk Power System, A Jointly‐
Commissioned Summary Report of the North American Reliability Corporation and the U.S.
Department of Energy’s November 2009 Workshop.
[2]
Application Guide: Computing Geomagnetically‐Induced Current in the Bulk‐Power System, NERC.
December 2013. http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force
%20GMDTF%202013/GIC%20Application%20Guide%202013_approved.pdfNERC.
[3]
Kuan Zheng, RistoBoteler, D. H.; Pirjola, David Boteler, Lian‐guang R. J.; Liu, L.; and Zheng, K.;
“Geoelectric Fields Due to Small‐Scale and Large‐Scale Source Currents”,.” IEEE Transactions on Power
Delivery, Vol. 28, No. 1, January 2013, pp. 442‐449.
[4]
Boteler, D. H. “Geomagnetically Induced Currents: Present Knowledge and Future Research”,.” IEEE
Transactions on Power Delivery, Vol. 9, No. 1, January 1994, pp. 50‐58.
[5]
Boteler, D. H. “Modeling Geomagnetically Induced Currents Produced by Realistic and Uniform Electric
Fields”,.” IEEE Transactions on Power Delivery, Vol. 13, No. 4, January 1998, pp. 1303‐1308.
[6]
J. L. Gilbert, W. A.J. L.; Radasky, E. B.W. A.; and Savage, E. B. “A Technique for Calculating the Currents
Induced by Geomagnetic Storms on Large High Voltage Power Grids”,.” Electromagnetic Compatibility
(EMC),). 2012 IEEE International Symposium on.
[7]
How to Calculate Electric Fields to Determine Geomagnetically‐Induced Currents. EPRI, Palo Alto, CA:
2013. 3002002149.
[8]
Pirjola, R.; Pulkkinen, A., R. Pirjola, .; and A. Viljanen, V. Statistics of extreme geomagnetically induced
current events, Space Weather, 6, S07001, doi:10.1029/2008SW000388, 2008.
[9]
Boteler, D. H.,. Assessment of geomagnetic hazard to power systems in Canada, Nat. Hazards, 23,
101–120,. 2001.
[10] Finnish Meteorological Institute’s IMAGE magnetometer chain data available at:
http://image.gsfc.nasa.gov/
[11] Boteler, D. H.,. and R. J. Pirjola, R. J. The complex‐image method for calculating the magnetic and
electric fields produced at the surface of the Earth by the auroral electrojet,. Geophys. J. Int., 132(1),
31—40,. 1998.
[12] Coles, Stuart (2001).S. An Introduction to Statistical Modelling of Extreme Values. Springer. 2001.
[13] Clarke, E.; Mckay, A.; Pulkkinen, A., A..; and Thomson, E. Clarke, and A. Mckay,A. April 2000
geomagnetic storm: ionospheric drivers of large geomagnetically induced currents,. Annales
Geophysicae, 21, 709‐717,. 2003.
[14] Lindahl, S.; Pirjola, R. J.; Pulkkinen, A., S. Lindahl, A. .; and Viljanen, and R. Pirjola,A. Geomagnetic
storm of 29–31 October 2003: Geomagnetically induced currents and their relation to problems in the
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References
Swedish high‐voltage power transmission system,. Space Weather, 3, S08C03,
doi:10.1029/2004SW000123,. 2005.
[15] Pulkkinen, A., E.Beggan, C.; Bernabeu, J.E.; Eichner, C. BegganJ.; Pulkkinen, A.; and A. Thomson, A.,
Generation of 100‐year geomagnetically induced current scenarios, Space Weather, Vol. 10, S04003,
doi:10.1029/2011SW000750,. 2012.
[16] Crowley, G.; Ngwira, C., A..; Pulkkinen, F.A.; and Wilder, and G. Crowley,F. Extended study of extreme
geoelectric field event scenarios for geomagnetically induced current applications,. Space Weather,
Vol. 11, 121–131, doi:10.1002/swe.20021,. 2013.
[17] Thomson, A., S.Dawson, E.; Reay, S.; and E. DawsonThomson, A. Quantifying extreme behavior in
geomagnetic activity,. Space Weather, 9, S10001, doi:10.1029/2011SW000696,. 2011.
NERC | Supplemental GMD Event Description (DRAFT)| June| October 2017
23
Screening Criterion for Transformer Thermal
Impact Assessment White Paper
TPL-007-2 Transmission System Planned Performance for
Geomagnetic Disturbance Events
Summary
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance
(GMD) Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric
System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL‐007‐1 which standard was approved by the Federal Energy Regulatory Commission (FERC)
in Order No. 830 in September 2016. The benchmark GMD event is derived from spatially‐averaged
geoelectric field values to address potential wide‐area effects that could be caused by a severe 1‐in‐
100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate risks that localized peaks in geomagnetic field during a severe GMD event
"could potentially affect the reliable operation of the Bulk‐Power System".2 Localized enhancements
of geomagnetic field can result in geoelectric field values above the spatially‐averaged benchmark
in a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye‐grounded windings with terminal voltage greater than 200 kV. Identified
BES transformers must undergo a thermal impact assessment if the maximum effective geomagnetically‐
induced current (GIC) in the transformer is equal to or greater than:
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
Based on published power transformer measurement data as described below, the respective screening
criteria are conservative and, although derived from measurements in single‐phase units, are applicable to
transformers with all core types (e.g., three‐limb, three‐phase).
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in Docket No. RM15‐11 on June 28,
2016.
2 See Order No. 830, P. 47. In Order No. 830, FERC directed NERC to develop modifications to the benchmark GMD event, included in TPL‐
007‐1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for this assessment
are in the Supplemental GMD Event Description white paper.
Outside of the differing screening criteria, the only difference between the thermal impact assessment for
the benchmark GMD event and the supplemental GMD event is that a different waveform is used, therefore
peak metallic hot spot temperatures are slightly different for a given GIC in the transformer.
Justification for the Benchmark Screening Criterion
Applicable entities are required to carry out a thermal assessment with GIC(t) calculated using the
benchmark GMD event geomagnetic field time series or waveform for effective GIC values above a
screening threshold. The calculated GIC(t) for every transformer will be different because the length and
orientation of transmission circuits connected to each transformer will be different even if the geoelectric
field is assumed to be uniform. However, for a given thermal model and maximum effective GIC there are
upper and lower bounds for the peak hot spot temperatures. These are shown in Figure 1 using three
available thermal models based on direct temperature measurements.
The results shown in Figure 1 summarize the peak metallic hot spot temperatures when GIC(t) is calculated
using (1), and systematically varying GICE and GICN to account for all possible orientation of circuits
connected to a transformer. The transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be
calculated using equation (1) from reference [1].
|
|
sin
cos
(1)
where
|
|
tan
(2)
(3)
(4)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km.
It should be emphasized that with the thermal models used and the benchmark GMD event geomagnetic
field waveform, peak metallic hot spot temperatures will lie below the envelope shown in black in Figure 1.
The x‐axis in Figure 1 corresponds to the absolute value of peak GIC(t). Effective maximum GIC for a
transformer corresponds to a worst‐case geoelectric field orientation, which is network‐specific. Figure 1
represents a possible range, not the specific thermal response for a given effective GIC and orientation.
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
2
Figure 1: Metallic hot spot temperatures calculated using the benchmark GMD event
Red: SVC coupling transformer model [2] Blue: Fingrid model [3] Green: Autotransformer model [4]
Consequently, with the most conservative thermal models known at this point in time, the peak metallic
hot spot temperature obtained with the benchmark GMD event waveform assuming an effective GIC
magnitude of 75 A per phase will result in a peak temperature between 160°C and 172°C when the bulk oil
temperature is 80°C (full load bulk oil temperature). The upper boundary of 172°C remains well below the
metallic hot spot 200°C threshold for short‐time emergency loading suggested in IEEE Std C57.91‐2011 –
Guide for Loading Mineral‐Oil‐Immersed Transformers and Step‐Voltage Regulators [5].
The selection of the 75 A per phase screening threshold is based on the following considerations:
A thermal assessment, which uses the most conservative thermal models known to date, indicates
that a GIC of 75A will not result in peak metallic hot spot temperatures above 172°C. Transformer
thermal assessments should not be required by Reliability Standards when results will fall well below
IEEE Std C57.91‐2011 limits.
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
3
Applicable entities may choose to carry out a thermal assessment when the effective GIC is below
75 A per phase to take into account the age or condition of specific transformers where IEEE Std
C57.91‐ 2011 limits could be assumed to be lower than 200°C. Refer to IEEE Standard C57.163‐2015
Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances for
additional information [6].
The models used to determine the 75 A per phase screening threshold are known to be conservative
at higher values of effective GIC, especially the SVC coupling transformer model in [2].
Thermal models in peer‐reviewed technical literature, especially those calculated models without
experimental validation, are less conservative than the models used to determine the screening
threshold. Therefore, a technically‐justified thermal assessment for effective GIC below 75 A per
phase using the benchmark GMD event geomagnetic field waveform will always result in a “pass”
on the basis of the state of the knowledge at this point in time.
Based on simulations, the 75 A per phase screening threshold will result in a maximum
instantaneous peak hot spot temperature of 172°C. However, IEEE Std C57.91‐2011 limits assume
short term emergency operation (typically 30 minutes). As illustrated in Figure 2, simulations of the
75 A per phase screening threshold result in 30‐minute duration hot spot temperatures of about
155°C. The threshold provides an added measure of conservatism in not taking into account the
duration of hot spot temperatures.
The models used in the determination of the threshold are conservative but technically justified.
Winding hot spots are not the limiting factor in terms of hot spots due to half‐cycle saturation,
therefore the screening criterion is focused on metallic part hot spots only.
The 75 A per phase screening threshold was determined using single‐phase transformers, but is being
applied as a screening criterion for all types of transformer construction. While it is known that some
transformer types such as three‐limb, three‐phase transformers are intrinsically less susceptible to GIC, it
is not known by how much, on the basis of experimentally‐supported models.
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
4
Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event
Red: metallic hot spot temperature
Blue: GIC(t) that produces the maximum hot spot temperature with peak GIC(t) scaled to 75 A/phase
Justification for the Supplemental Screening Criterion
As in the case for the benchmark GMD event discussed above, applicable entities are required to carry out
thermal assessments on their BES power transformers when the effective GIC values are above a screening
threshold. GIC(t) for supplemental thermal assessments is calculated using the supplemental GMD event
geomagnetic field time series or waveform.
Using the supplemental GMD event waveform, a thermal analysis was completed for the two transformers
that were limiting for the benchmark waveform. The results are shown in Figure 3. Peak metallic hot spot
temperatures for the supplemental GMD event will lie below the envelope shown by the black line trace in
Figure 3. Because the supplemental waveform has a sharper peak, the peak metallic hot spot temperatures
are slightly lower than those associated with the benchmark waveform. Applying the most conservative
thermal models known at this point in time, the peak metallic hot spot temperature obtained with the
supplemental GMD event waveform assuming an effective GIC magnitude of 85 A per phase will result in a
peak temperature of 172°C when the bulk oil temperature is 80°C (full load bulk oil temperature).3 Thus, 85
A per phase is the screening level for the supplemental waveform.
3 The temperature 172°C was selected as the screening criteria for the benchmark waveform as described in the preceding section.
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
5
Figure 3: Metallic hot spot temperatures calculated using the supplemental GMD event
Red: SVC coupling transformer model [2] Green: Autotransformer model [4]
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
6
Appendix I - Transformer Thermal Models Used in the Development of the
Screening Criteria
The envelope used for thermal screening (Figure 1) is derived from two thermal models. The first is based
on laboratory measurements carried out on 500/16.5 kV 400 MVA single‐phase Static Var Compensator
(SVC) coupling transformer [2]. Temperature measurements were carried out at relatively small values of
GIC (see Figure I‐1). The asymptotic thermal response for this model is the linear extrapolation of the known
measurement values. Although the near‐linear behavior of the asymptotic thermal response is consistent
with the measurements made on a Fingrid 400 kV 400 MVA five‐leg core‐type fully‐wound transformer [3]
(see Figures I‐2 and I‐3), the extrapolation from low values of GIC is very conservative, but reasonable for
screening purposes.
The second transformer model is based on a combination of measurements and modeling for a 400 kV 400
MVA single‐phase core‐type autotransformer [4] (see Figures I‐4 and I‐5). The asymptotic thermal behavior
of this transformer shows a “down‐turn” at high values of GIC as the tie plate increasingly saturates but
relatively high temperatures for lower values of GIC. The hot spot temperatures are higher than for the two
other models for GIC less than 125 A per phase.
18
Temperature (deg. C)
16
14
12
10
8
6
4
2
0
0
5
10
15
20
25
30
Time (min)
Figure I-1: Thermal step response of the tie plate of a 500 kV 400 MVA single-phase SVC
coupling transformer to a 5 A per phase dc step
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
7
35
Temperature (deg. C)
30
25
20
15
10
5
0
0
5
10
15
20
25
30
35
40
45
Time (min)
Figure I-2: Step thermal response of the top yoke clamp of a 400 kV 400 MVA five-leg coretype fully-wound transformer to a 16.67 A per phase dc step
200
Temperature (deg. C)
180
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-3: Asymptotic thermal response of the top yoke clamp of a 400 kV 400 MVA fiveleg core-type fully-wound transformer
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
8
Figure I-4: Step thermal response of the tie plate of a 400 kV 400 MVA single-phase coretype autotransformer to a 10 A per phase dc step
180
Temperature (deg. C)
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-5: Asymptotic thermal response of the tie plate of a 400 kV 400 MVA single-phase
core-type autotransformer
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
9
The envelope in Figure 1 can be used as a conservative thermal assessment for effective GIC values of
associated with the benchmark waveform and reference earth model (see Table 1).
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
90
Metallic hot spot
Temperature (°C)
80
107
128
139
148
157
169
170
172
175
179
Effective GIC
(A/phase)
100
110
120
130
140
150
160
170
180
190
200
Metallic hot spot
Temperature (°C)
182
186
190
193
204
213
221
230
234
241
247
For instance, if effective GIC is 130 A per phase and oil temperature is assumed to be 80°C, peak hot spot
temperature is 193°C. This value is below the 200°C IEEE Std C57.91‐2011 threshold for short time
emergency loading and this transformer will have passed the thermal assessment. If the full heat run oil
temperature is 67°C at maximum ambient temperature, then 150 A per phase of effective GIC translates
into a peak hot spot temperature of 200°C and the transformer will have passed. If the limit is lowered to
180°C to account for the condition of the transformer, then this would be an indication to “sharpen the
pencil” and perform a detailed assessment. Some methods are described in Reference [1].
The temperature envelope in Figure 1 corresponds to the values of effective GIC that result in the highest
temperature for the benchmark GMD event. Different values of effective GIC could result in lower
temperatures using the same model. For instance, the difference in upper and lower bounds of peak
temperatures for the SVC coupling transformer model for 150 A per phase is approximately 30°C. In this
case, GIC(t) should be generated to calculate the peak temperatures for the actual configuration of the
transformer within the system as described in Reference [1]. Alternatively, a more precise thermal
assessment could be carried out with a thermal model that more closely represents the thermal behavior
of the transformer under consideration.
Similar to the discussion above, the envelope in Figure 3 can be used as a conservative thermal assessment
for effective GIC values of associated with the supplemental waveform (see Table 2). The supplemental
waveform has a sharper peak; therefore, the peak metallic hot spot temperatures associated with the
supplemental waveform for the same peak current are slightly lower than those associated with the
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
10
benchmark waveform. In other words, for the same peak current value, the duration is relatively shorter
with the supplemental waveform, and shorter duration means lower temperature. However, higher peak
currents will occur with the supplemental benchmark, therefore, higher peak hot spot temperatures will
occur. Comparing Tables 1 and 2 shows the magnitude of this difference.
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
85
90
100
110
Metallic hot spot
Temperature (°C )
80
107
124
137
147
156
161
162
165
169
172
177
181
185
Effective
GIC(A/phase)
120
130
140
150
160
170
180
190
200
220
230
250
275
300
Metallic hot spot
Temperature (°C )
188
191
194
198
203
209
214
229
237
248
253
276
298
316
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
11
References
[1] Transformer Thermal Impact Assessment white paper. Developed by the Project 2013‐03 (Geomagnetic
Disturbance) standard drafting team. October 2017. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[2] Marti, L; Rezaei‐Zare, A.; and Narang, A. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents." IEEE Transactions on Power Delivery, vol.28, no.1, pp.320‐327, Jan.
2013.
[3] Lahtinen, M. and Elovaara, J. “GIC occurrences and GIC test for 400 kV system transformer”. IEEE
Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
[4] Raith, J. and Ausserhofer, S. “GIC Strength verification of Power Transformers in a High Voltage
Laboratory”, GIC Workshop, Cape Town, April 2014
[5] "IEEE Guide for Loading Mineral‐Oil‐Immersed Transformers and Step‐Voltage Regulators." IEEE Std
C57.91‐2011 (Revision of IEEE Std C57.91‐1995).
[6] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.” IEEE
Std C57.163‐2015.
Screening Criterion for Transformer Thermal Impact Assessment White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation |October 2017
12
Screening Criterion for Transformer Thermal
Impact Assessment White Paper
Project 2013-03 (Geomagnetic Disturbance Mitigation)
TPL-007-2 Transmission System Planned Performance for
Geomagnetic Disturbance Events
Summary
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance
(GMD) Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric
System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL‐007‐1 which standard was approved by the Federal Energy Regulatory Commission (FERC)
in Order No. 830 in September 2016. The benchmark GMD event is derived from spatially‐averaged
geoelectric field values to address potential wide‐area effects that could be caused by a severe 1‐in‐
100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate risks that localized peaks in geomagnetic field during a severe GMD event
"could potentially affect the reliable operation of the Bulk‐Power System".2 Localized enhancements
of geomagnetic field can result in geoelectric field values above the spatially‐averaged benchmark
in a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye‐grounded windings with terminal voltage greater than 200 kV. Identified
BES transformers must undergo a thermal impact assessment if the maximum effective geomagnetically‐
induced current (GIC) in the transformer is equal to or greater than:
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in Docket No. RM15‐11 on June 28,
2016.
2 See Order No. 830, P. 47. On September 22, 2016In Order No. 830, FERC directed NERC to develop modifications to the benchmark GMD
event, included in TPL‐007‐1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event
for this assessment are in the Supplemental GMD Event Description white paper.
Based on published power transformer measurement data as described below, the respective screening
criteria are conservative and, although derived from measurements in single‐phase units, are applicable to
transformers with all core types (e.g., three‐limb, three‐phase).
Outside of the differing screening criteria, the only difference between the thermal impact assessment for
the benchmark GMD event and the supplemental GMD event is that a different waveform is used, therefore
peak metallic hot spot temperatures are slightly different for a given GIC in the transformer.
Justification for the Benchmark Screening Criterion
Applicable entities are required to carry out a thermal assessment with GIC(t) calculated using the
benchmark GMD event geomagnetic field time series or waveform for effective GIC values above a
screening threshold. The calculated GIC(t) for every transformer will be different because the length and
orientation of transmission circuits connected to each transformer will be different even if the geoelectric
field is assumed to be uniform. However, for a given thermal model and maximum effective GIC there are
upper and lower bounds for the peak hot spot temperatures. These are shown in Figure 1 using three
available thermal models based on direct temperature measurements.
The results shown in Figure 1 summarize the peak metallic hot spot temperatures when GIC(t) is calculated
using (1), and systematically varying GICE and GICN to account for all possible orientation of circuits
connected to a transformer. The transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be
calculated using equation (1) from reference [1].
|
|
sin
cos
(1)
where
|
|
tan
(2)
(3)
(4)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km.
It should be emphasized that with the thermal models used and the benchmark GMD event geomagnetic
field waveform, peak metallic hot spot temperatures will lie below the envelope shown in black in Figure 1.
The x‐axis in Figure 1 corresponds to the absolute value of peak GIC(t). Effective maximum GIC for a
transformer corresponds to a worst‐case geoelectric field orientation, which is network‐specific. Figure 1
represents a possible range, not the specific thermal response for a given effective GIC and orientation.
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
2
Figure 1: Metallic hot spot temperatures calculated using the benchmark GMD event
Red: SVC coupling transformer model [2] Blue: Fingrid model [3] Green: Autotransformer model [4]
Consequently, with the most conservative thermal models known at this point in time, the peak metallic
hot spot temperature obtained with the benchmark GMD event waveform assuming an effective GIC
magnitude of 75 A per phase will result in a peak temperature between 160°C and 172°C when the bulk oil
temperature is 80°C (full load bulk oil temperature). The upper boundary of 172°C remains well below the
metallic hot spot 200°C threshold for short‐time emergency loading suggested in IEEE Std C57.91‐2011 ̶–
Guide for Loading Mineral‐Oil‐Immersed Transformers and Step‐Voltage Regulators [5].
The selection of the 75 A per phase screening threshold is based on the following considerations:
A thermal assessment, which uses the most conservative thermal models known to date, indicates
that a GIC of 75A will not result in peak metallic hot spot temperatures above 172°C. Transformer
thermal assessments should not be required by Reliability Standards when results will fall well below
IEEE Std C57.91‐2011 limits.
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
3
Applicable entities may choose to carry out a thermal assessment when the effective GIC is below
75 A per phase to take into account the age or condition of specific transformers where IEEE Std
C57.91‐ 2011 limits could be assumed to be lower than 200°C. Refer to IEEE Standard C57.163‐2015
Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances for
additional information [6].
The models used to determine the 75 A per phase screening threshold are known to be conservative
at higher values of effective GIC, especially the SVC coupling transformer model in [2].
Thermal models in peer‐reviewed technical literature, especially those calculated models without
experimental validation, are less conservative than the models used to determine the screening
threshold. Therefore, a technically‐justified thermal assessment for effective GIC below 75 A per
phase using the benchmark GMD event geomagnetic field waveform will always result in a “pass”
on the basis of the state of the knowledge at this point in time.
Based on simulations, the 75 A per phase screening threshold will result in a maximum
instantaneous peak hot spot temperature of 172°C. However, IEEE Std C57.91‐2011 limits assume
short term emergency operation (typically 30 minutes). As illustrated in Figure 2, simulations of the
75 A per phase screening threshold result in 30‐minute duration hot spot temperatures of about
155°C. The threshold provides an added measure of conservatism in not taking into account the
duration of hot spot temperatures.
The models used in the determination of the threshold are conservative but technically justified.
Winding hot spots are not the limiting factor in terms of hot spots due to half‐cycle saturation,
therefore the screening criterion is focused on metallic part hot spots only.
The 75 A per phase screening threshold was determined using single‐phase transformers, but is being
applied as a screening criterion for all types of transformer construction. While it is known that some
transformer types such as three‐limb, three‐phase transformers are intrinsically less susceptible to GIC, it
is not known by how much, on the basis of experimentally‐supported models.
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
4
Figure 2: Metallic hot spot temperatures calculated using the benchmark GMD event
Red: metallic hot spot temperature
Blue: GIC(t) that produces the maximum hot spot temperature with peak GIC(t) scaled to 75 A/phase
Justification for the Supplemental Screening Criterion
As in the case for the benchmark GMD event discussed above, applicable entities are required to carry out
thermal assessments on their BES power transformers when the effective GIC values are above a screening
threshold. GIC(t) for supplemental thermal assessments is calculated using the supplemental GMD event
geomagnetic field time series or waveform.
Using the supplemental GMD event waveform, a thermal analysis was completed for the two transformers
that were limiting for the benchmark waveform. The results are shown in Figure 3. Peak metallic hot spot
temperatures for the supplemental GMD event will lie below the envelope shown by the black line trace in
Figure 3. Because the supplemental waveform has a sharper peak, the peak metallic hot spot temperatures
are slightly lower than those associated with the benchmark waveform. Applying the most conservative
thermal models known at this point in time, the peak metallic hot spot temperature obtained with the
supplemental GMD event waveform assuming an effective GIC magnitude of 85 A per phase will result in a
peak temperature of 172°C when the bulk oil temperature is 80°C (full load bulk oil temperature).3 Thus, 85
A per phase is the screening level for the supplemental waveform.
3
The temperature 172°C was selected as the screening criteria for the benchmark waveform as described in the preceding section.
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
5
Figure 3: Metallic hot spot temperatures calculated using the supplemental GMD event
Red: SVC coupling transformer model [2] Green: Autotransformer model [4]
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
6
Appendix I - Transformer Thermal Models Used in the Development of the
Screening Criteria
The envelope used for thermal screening (Figure 1) is derived from two thermal models. The first is based
on laboratory measurements carried out on 500/16.5 kV 400 MVA single‐phase Static Var Compensator
(SVC) coupling transformer [2]. Temperature measurements were carried out at relatively small values of
GIC (see Figure I‐1). The asymptotic thermal response for this model is the linear extrapolation of the known
measurement values. Although the near‐linear behavior of the asymptotic thermal response is consistent
with the measurements made on a Fingrid 400 kV 400 MVA five‐leg core‐type fully‐wound transformer [3]
(see Figures I‐2 and I‐3), the extrapolation from low values of GIC is very conservative, but reasonable for
screening purposes.
The second transformer model is based on a combination of measurements and modeling for a 400 kV 400
MVA single‐phase core‐type autotransformer [4] (see Figures I‐4 and I‐5). The asymptotic thermal behavior
of this transformer shows a “down‐turn” at high values of GIC as the tie plate increasingly saturates but
relatively high temperatures for lower values of GIC. The hot spot temperatures are higher than for the two
other models for GIC less than 125 A per phase.
18
Temperature (deg. C)
16
14
12
10
8
6
4
2
0
0
5
10
15
20
25
30
Time (min)
Figure I-1: Thermal step response of the tie plate of a 500 kV 400 MVA single-phase SVC
coupling transformer to a 5 A per phase dc step
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
7
35
Temperature (deg. C)
30
25
20
15
10
5
0
0
5
10
15
20
25
30
35
40
45
Time (min)
Figure I-2: Step thermal response of the top yoke clamp of a 400 kV 400 MVA five-leg coretype fully-wound transformer to a 16.67 A per phase dc step
200
Temperature (deg. C)
180
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-3: Asymptotic thermal response of the top yoke clamp of a 400 kV 400 MVA fiveleg core-type fully-wound transformer
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
8
Figure I-4: Step thermal response of the tie plate of a 400 kV 400 MVA single-phase coretype autotransformer to a 10 A per phase dc step
180
Temperature (deg. C)
160
140
120
100
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
100
GIC (A/phase)
Figure I-5: Asymptotic thermal response of the tie plate of a 400 kV 400 MVA single-phase
core-type autotransformer
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
9
The envelope in Figure 1 can be used as a conservative thermal assessment for effective GIC values of
associated with the benchmark waveform and reference earth model (see Table 1).
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
90
Metallic hot spot
Temperature (°C)
80
107
128
139
148
157
169
170
172
175
179
Effective GIC
(A/phase)
100
110
120
130
140
150
160
170
180
190
200
Metallic hot spot
Temperature (°C)
182
186
190
193
204
213
221
230
234
241
247
For instance, if effective GIC is 130 A per phase and oil temperature is assumed to be 80°C, peak hot spot
temperature is 193°C. This value is below the 200°C IEEE Std C57.91‐2011 threshold for short time
emergency loading and this transformer will have passed the thermal assessment. If the full heat run oil
temperature is 67°C at maximum ambient temperature, then 150 A per phase of effective GIC translates
into a peak hot spot temperature of 200°C and the transformer will have passed. If the limit is lowered to
180°C to account for the condition of the transformer, then this would be an indication to “sharpen the
pencil” and perform a detailed assessment. Some methods are described in Reference [1].
The temperature envelope in Figure 1 corresponds to the values of effective GIC that result in the highest
temperature for the benchmark GMD event. Different values of effective GIC could result in lower
temperatures using the same model. For instance, the difference in upper and lower bounds of peak
temperatures for the SVC coupling transformer model for 150 A per phase is approximately 30°C. In this
case, GIC(t) should be generated to calculate the peak temperatures for the actual configuration of the
transformer within the system as described in Reference [1]. Alternatively, a more precise thermal
assessment could be carried out with a thermal model that more closely represents the thermal behavior
of the transformer under consideration.
Similar to the discussion above, the envelope in Figure 3 can be used as a conservative thermal assessment
for effective GIC values of associated with the supplemental waveform (see Table 2). Because theThe
supplemental waveform has a sharper peak; therefore, the peak metallic hot spot temperatures associated
with the supplemental waveform for the same peak current are slightly lower than those associated with
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
10
the benchmark waveform. In other words, for the same peak current value, the duration is relatively shorter
with the supplemental waveform, and shorter duration means lower temperature. However, higher peak
currents will occur with the supplemental benchmark, therefore, higher peak hot spot temperatures will
occur. Comparing Tables 1 and 2 shows the magnitude of this difference.
Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC
(A/phase)
0
10
20
30
40
50
60
70
75
80
85
90
100
110
Metallic hot spot
Temperature (°C )
80
107
124
137
147
156
161
162
165
169
172
177
181
185
Effective
GIC(A/phase)
120
130
140
150
160
170
180
190
200
220
230
250
275
300
Metallic hot spot
Temperature (°C )
188
191
194
198
203
209
214
229
237
248
253
276
298
316
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
11
References
[1] Transformer Thermal Impact Assessment white paper. Developed by the Project 2013‐03 (Geomagnetic
Disturbance) standard drafting team. October 2017. Available at:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx
[2] Marti, L.,; Rezaei‐Zare, A.,.; and Narang, A.,. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents,"." IEEE Transactions on Power Delivery, vol.28, no.1, pp.320‐327,
Jan. 2013.
[3] Lahtinen, Matti. JarmoM. and Elovaara, J. “GIC occurrences and GIC test for 400 kV system transformer”.
IEEE Transactions on Power Delivery, Vol. 17, No. 2. April 2002.
[4] J. Raith, S.J. and Ausserhofer:, S. “GIC Strength verification of Power Transformers in a High Voltage
Laboratory”, GIC Workshop, Cape Town, April 2014
[5] "IEEE Guide for Loading Mineral‐Oil‐Immersed Transformers and Step‐Voltage Regulators." IEEE Std
C57.91‐2011 (Revision of IEEE Std C57.91‐1995).
[6] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.” IEEE
Std C57.163‐2015.
Screening Criterion for Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 (Geomagnetic Disturbance Mitigation) | June |October 2017
12
Transformer Thermal Impact Assessment
White Paper
TPL-007-2 – Transmission System Planned Performance for
Geomagnetic Disturbance Events
Background
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance
(GMD) Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric
System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL‐007‐1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially‐averaged
geoelectric field values to address potential wide‐area effects that could be caused by a severe 1‐in‐
100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate localized peaks in geomagnetic field during a severe GMD event that "could
potentially affect the reliable operation of the Bulk‐Power System."2 Localized enhancements of
geomagnetic field can result in geoelectric field values above the spatially‐averaged benchmark in
a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye‐grounded windings with terminal voltage greater than 200 kV. Large
power transformers connected to the extra‐high voltage (EHV) transmission system can experience both
winding and structural hot spot heating as a result of GMD events. TPL‐007‐2 requires owners of such BES
transformers to conduct thermal analyses to determine if the BES transformers will be able to withstand
the thermal transient effects associated with the GMD events. BES transformers must undergo a thermal
impact assessment if the maximum effective geomagnetically‐induced current (GIC) in the transformer is
equal to or greater than:3
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
This white paper discusses methods that can be employed to conduct transformer thermal impact
assessments, including example calculations. The first version of the white paper was developed by the
Project 2013‐03 GMD Standards Drafting Team (SDT) for TPL‐007‐1 and was endorsed by the Electric
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15‐11 on June 28, 2016.
2 See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event, included in
TPL‐007‐1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for this
assessment are in the Supplemental GMD Event Description white paper.
3 See Screening Criterion for Transformer Thermal Impact Assessment for technical justification.
Reliability Organization (ERO) as implementation guidance in October 2016. The SDT has updated the white
paper to include the supplemental GMD event that is added in TPL‐007‐2 to address directives in FERC
Order No. 830.
The primary impact of GMDs on large power transformers is a result of the quasi‐dc current that flows
through wye‐grounded transformer windings. This GIC results in an offset of the ac sinusoidal flux resulting
in asymmetric or half‐cycle saturation (see Figure 1).
Half‐cycle saturation results in a number of known effects:
Hot spot heating of transformer windings due to harmonics and stray flux;
Hot spot heating of non‐current carrying transformer metallic members due to stray flux;
Harmonics;
Increase in reactive power absorption; and
Increase in vibration and noise level.
Figure 1: Mapping Magnetization Current to Flux through Core Excitation Characteristics
This paper focuses on hot spot heating of transformer windings and non‐current‐carrying metallic parts.
Effects such as the generation of harmonics, increase in reactive power absorption, vibration, and noise
are not within the scope of this document.
Transformer Thermal Impact Assessment White Paper
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Technical Considerations
The effects of half‐cycle saturation on high‐voltage (HV) and EHV transformers, namely localized “hot spot”
heating, are relatively well understood, but are difficult to quantify. A transformer GMD impact assessment
must consider GIC amplitude, duration, and transformer physical characteristics such as design and
condition (e.g., age, gas content, and moisture in the oil). A single threshold value of GIC cannot be justified
as a “pass or fail” screening criterion where “fail” means that the transformer will suffer damage. A single
threshold value of GIC only makes sense in the context where “fail” means that a more detailed study is
required. Such a threshold would have to be technically justifiable and sufficiently low to be considered a
conservative value of GIC.
The following considerations should be taken into account when assessing the thermal susceptibility of a
transformer to half‐cycle saturation:
In the absence of manufacturer specific information, use the temperature limits for safe transformer
operation such as those suggested in the IEEE Std C57.91‐2011 (IEEE Guide for Loading Mineral‐oil‐
immersed Transformers and Step‐voltage Regulators) for hot spot heating during short‐term
emergency operation [1]. This standard does not suggest that exceeding these limits will result in
transformer failure, but rather that it will result in additional aging of cellulose in the paper‐oil
insulation and the potential for the generation of gas bubbles in the bulk oil. Thus, from the point
of view of evaluating possible transformer damage due to increased hot spot heating, these
thresholds can be considered conservative for a transformer in good operational condition.
The worst case temperature rise for winding and metallic part (e.g., tie plate) heating should be
estimated taking into consideration the construction characteristics of the transformer as they
pertain to dc flux offset in the core (e.g., single‐phase, shell, 5 and 3‐leg three‐phase construction).
Bulk oil temperature due to ambient temperature and transformer loading must be added to the
incremental temperature rise caused by hot spot heating. For planning purposes, maximum ambient
and loading temperature should be used unless there is a technically justified reason to do
otherwise.
The time series or “waveform” of the reference GMD event in terms of peak amplitude, duration,
and frequency of the geoelectric field has an important effect on hot spot heating. Winding and
metallic part hot spot heating have different thermal time constants, and their temperature rise will
be different if the GIC currents are sustained for 2, 10, or 30 minutes for a given GIC peak amplitude.
The “effective” GIC in autotransformers (reflecting the different GIC ampere‐turns in the common
and the series windings) must be used in the assessment. The effective current Idc,eq in an
autotransformer is defined by [2].
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,
⁄3
⁄
(1)
where
IH is the dc current in the high voltage winding;
IN is the neutral dc current;
VH is the root mean square (rms) rated voltage at HV terminals; and
VX is the rms rated voltage at the LV terminals.
Transformer Thermal Impact Assessment Process
A simplified thermal assessment may be based on the appropriate tables from the “Screening Criterion for
Transformer Thermal Impact Assessment” white paper [3].4 Each table below provides the peak metallic
hot spot temperatures that can be reached for the given GMD event using conservative thermal models.
To use each table, one must select the bulk oil temperature and the threshold for metallic hot spot heating,
for instance, from reference [1] after allowing for possible de‐rating due to transformer condition. If the
effective GIC results in higher than threshold temperatures, then the use of a detailed thermal assessment
as described below should be carried out.5
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
(A/phase)
Temperature (C )
Temperature (C )
0
80
100
182
10
107
110
186
20
128
120
190
30
139
130
193
40
148
140
204
50
157
150
213
60
169
160
221
70
170
170
230
75
172
180
234
80
175
190
241
90
179
200
247
4 Table 1 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound temperatures for the
benchmark GMD event. Table 2 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound
temperatures for the supplemental GMD event.
5 Effective GIC in the table is the peak GIC(t) for the GMD event being assessed. Peak GIC(t) is not steady‐state GIC.
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Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
(A/phase)
Temperature (C)
Temperature (C)
0
80
120
188
10
107
130
191
20
124
140
194
30
137
150
198
40
147
160
203
50
156
170
209
60
161
180
214
70
162
190
229
75
165
200
237
80
169
220
248
85
172
230
253
90
177
250
276
100
181
275
298
110
185
300
316
Two different ways to carry out a detailed thermal impact assessment are discussed below. In addition,
other approaches and models approved by international standard‐setting organizations such as the
Institute of Electrical and Electronic Engineers (IEEE) or International Council on Large Electric Systems
(CIGRE) may also provide technically justified methods for performing thermal assessments.6 All thermal
assessment methods should be demonstrably equivalent to assessments that use the GMD events
associated with TPL‐007‐2.
1. Transformer manufacturer GIC capability curves. These curves relate permissible peak GIC (obtained
by the user from a steady‐state GIC calculation) and loading, for a specific transformer. An example
of manufacturer capability curves is provided in Figure 2. Presentation details vary between
manufacturers, and limited information is available regarding the assumptions used to generate
these curves, in particular, the assumed waveshape or duration of the effective GIC. Some
manufacturers assume that the waveform of the GIC in the transformer windings is a square pulse
of 2, 10, or 30 minutes in duration. In the case of the transformer capability curve shown in Figure
2, a square pulse of 900 A/phase with a duration of 2 minutes would cause the Flitch plate hot spot
to reach a temperature of 180C at full load [5]. While GIC capability curves are relatively simple to
use, an amount of engineering judgment is necessary to ascertain which portion of a GIC waveform
is equivalent to, for example, a 2 minute pulse. Also, manufacturers generally maintain that in the
absence of transformer standards defining thermal duty due to GIC, such capability curves must be
developed for every transformer design and vintage.
6 For example, C57.163‐2015 – IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances. [4]
Transformer Thermal Impact Assessment White Paper
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100
Flitch Plate Temp = 180 C for 2 Minutes
90
Flitch Plate Temp = 160 C for 30 Minutes
% MVA Rating
80
70
60
50
40
30
600
800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000
GIC, Amps/Phase
Figure 2: Sample GIC Manufacturer Capability Curve of a Large Single-Phase Transformer
Design using the Flitch Plate Temperature Criteria [5]
2. Thermal response simulation.7 The input to this type of simulation is the time series or waveform of
effective GIC flowing through a transformer (taking into account the actual configuration of the
system), and the result of the simulation is the hot spot temperature (winding or metallic part) time
sequence for a given transformer. An example of GIC input and hotspot temperature time series
values from [6] are shown in Figure 3. The hot spot thermal transfer functions can be obtained from
measurements or calculations provided by transformer manufacturers. Conservative default values
can be used (e.g., those provided in [6]) when specific data are not available. Hot spot temperature
thresholds shown in Figure 3 are consistent with IEEE Std C57.91‐2011 emergency loading hot spot
limits. Emergency loading time limit is usually 30 minutes.
7 Technical details of this methodology can be found in [6].
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Figure 3: Sample Tie Plate Temperature Calculation
Blue trace is incremental temperature and red trace is the magnitude of the GIC/phase [6]
It is important to reiterate that the characteristics of the time sequence or “waveform” are very important
in the assessment of the thermal impact of GIC on transformers. Transformer hot spot heating is not
instantaneous. The thermal time constants of transformer windings and metallic parts are typically on the
order of minutes to tens of minutes; therefore, hot spot temperatures are heavily dependent on GIC history
and rise time, amplitude and duration of GIC in the transformer windings, bulk oil temperature due to
loading, ambient temperature and cooling mode.
Calculation of the GIC Waveform for a Transformer
The following procedure can be used to generate time series GIC data (i.e., GIC(t)) using a software program
capable of computing GIC in the steady‐state. The steps are as follows:
1. Calculate contribution of GIC due to eastward and northward geoelectric fields for the transformer
under consideration; and
2. Scale the GIC contribution according to the reference geoelectric field time series to produce the
GIC time series for the transformer under consideration.
Most available GIC–capable software packages can calculate GIC in steady‐state in a transformer assuming
a uniform eastward geoelectric field of 1 V/km (GICE) while the northward geoelectric field is zero. Similarly,
GICN can be obtained for a uniform northward geoelectric field of 1 V/km while the eastward geoelectric
field is zero. GICE and GICN are the normalized GIC contributions for the transformer under consideration.
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If the earth conductivity is assumed to be uniform (or laterally uniform) in the transmission system of
interest, then the transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be calculated using (2)
[2].
|
|
sin
cos
(2)
where,
|
|
tan
(3)
(4)
(5)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km).
The geoelectric field time series EN(t) and EE(t) is obtained, for instance, from the reference geomagnetic
field time series (from [7] and/or [8]) after the appropriate geomagnetic latitude scaling factor is applied.8
The reference geoelectric field time series is calculated using the reference earth model. When using this
geoelectric field time series where a different earth model is applicable, it should be scaled with the
appropriate conductivity scaling factor .9 Alternatively, the geoelectric field can be calculated from the
reference geomagnetic field time series after the appropriate geomagnetic latitude scaling factor is
applied and the appropriate earth model is used. In such case, the conductivity scaling factor is not applied
because it is already accounted for by the use of the appropriate earth model.
Applying (5) to each point in EN(t) and EE(t) results in GIC(t).
GIC(t) Calculation Example
Let us assume that from the steady‐state solution, the effective GIC in this transformer is GICE = ‐20 A/phase
if EN=0, EE=1 V/km and GICN = 26 A/phase if EN=1 V/km, EE=0. Let us also assume the geomagnetic field time
8 The geomagnetic factor is described in [2] and is used to scale the geomagnetic field according to geomagnetic latitude. The lower the
geomagnetic latitude (closer to the equator), the lower the amplitude of the geomagnetic field.
9 The conductivity scaling factor is described in [2], and is used to scale the geoelectric field according to the conductivity of different
physiographic regions. Lower conductivity results in higher scaling factors.
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series corresponds to a geomagnetic latitude where = 1 and that the earth conductivity corresponds to
the reference earth model in [7]. The resulting geoelectric field time series is shown in Figure 4. Therefore:
⁄
20
26
⁄
(6)
(7)
The resulting GIC waveform GIC(t) is shown in Figures 5 and 6 and can subsequently be used for thermal
analysis.
It should be emphasized that even for the same reference event, the GIC(t) waveform in every transformer
will be different, depending on the location within the system and the number and orientation of the
circuits connecting to the transformer station. Assuming a single generic GIC(t) waveform to test all
transformers is incorrect.
Figure 4: Calculated Geoelectric Field EN(t) and EE(t) Assuming =1 and =1
(Reference Earth Model)
Zoom area for subsequent graphs is highlighted
Dashed lines approximately show the close-up area for subsequent Figures
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Figure 5: Calculated GIC(t) Assuming =1 and =1
Reference Earth Model
Figure 6: Calculated Magnitude of GIC(t) Assuming =1 and =1
Reference Earth Model
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Transformer Thermal Assessment Examples
There are two basic ways to carry out a transformer thermal analysis once the GIC time series GIC(t) is
known for a given transformer: 1) calculating the thermal response as a function of time; and 2) using
manufacturer’s capability curves.
Example 1: Calculating thermal response as a function of time using a thermal response tool
The thermal step response of the transformer can be obtained for both winding and metallic part hot spots
from: 1) measurements; 2) manufacturer’s calculations; or 3) generic published values. Figure 7 shows the
measured metallic hot spot thermal response to a dc step of 16.67 A/phase of the top yoke clamp from [9]
that will be used in this example. Figure 8 shows the measured incremental temperature rise (asymptotic
response) of the same hot spot to long duration GIC steps.10
Figure 7: Thermal Step Response to a 16.67 Amperes per Phase dc Step
Metallic hot spot heating
10 Heating of bulk oil due to the hot spot temperature increase is not included in the asymptotic response because the time constant of bulk
oil heating is at least an order of magnitude larger than the time constants of hot spot heating.
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Figure 8: Asymptotic Thermal Step Response
Metallic hot spot heating
The step response in Figure 7 was obtained from the first GIC step of the tests carried out in [6]. The
asymptotic thermal response in Figure 8 was obtained from the final or near‐final temperature values after
each subsequent GIC step. Figure 9 shows a comparison between measured temperatures and the
calculated temperatures using the thermal response model used in the rest of this discussion.
Figure 9: Comparison of measured temperatures (red) and simulation results (blue)
Injected current is represented by magenta
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To obtain the thermal response of the transformer to a GIC waveform such as the one in Figure 6, a thermal
response model is required. To create a thermal response model, the measured or manufacturer‐calculated
transformer thermal step responses (winding and metallic part) for various GIC levels are required. The
GIC(t) time series or waveform is then applied to the thermal model to obtain the incremental temperature
rise as a function of time (t) for the GIC(t) waveform. The total temperature is calculated by adding the oil
temperature, for example, at full load.
Figure 10 illustrates the calculated GIC(t) and the corresponding metallic hot spot temperature time series
(t). Figure 11 illustrates a close‐up view of the peak transformer temperatures calculated in this example.
Figure 10: Magnitude of GIC(t) and Metallic Hot Spot Temperature (t) Assuming Full Load
Oil Temperature of 85.3C (40C ambient)
Dashed lines approximately show the close-up area for subsequent figures
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Figure 11: Close-up of Metallic Hot Spot Temperature Assuming a Full Load
Blue trace is (t) Red trace is GIC(t)
In this example, the IEEE Std C57.91‐2011 emergency loading hot spot threshold of 200C for metallic hot
spot heating is not exceeded. Peak temperature is 186C. The IEEE standard is silent as to whether the
temperature can be higher than 200C for less than 30 minutes. Manufacturers can provide guidance on
individual transformer capability.
It is not unusual to use a lower temperature threshold of 180C to account for calculation and data margins,
as well as transformer age and condition. Figure 11 shows that 180C will be exceeded for 5 minutes.
At 75% loading, the initial temperature is 64.6C rather than 85.3C, and the hot spot temperature peak is
165C, well below the 180C threshold (see Figure 12).
If a conservative threshold of 160C were used to account for the age and condition of the transformer,
then the full load limits would be exceeded for approximately 22 minutes.
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Figure 12: Close-up of Metallic Hot Spot Temperature Assuming a 75% Load
Oil temperature of 64.5C
Example 2: Using a Manufacturer’s Capability Curves
The capability curves used in this example are shown in Figure 13. To maintain consistency with the previous
example, these particular capability curves have been reconstructed from the thermal step response shown
in Figures 7 and 8, and the simplified loading curve shown in Figure 14 (calculated using formulas from IEEE
Std C57.91‐2011).
Figure 13: Capability Curve of a Transformer Based on the Thermal Response Shown in
Figures 8 and 9
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Figure 14: Simplified Loading Curve Assuming 40C Ambient Temperature
The basic notion behind the use of capability curves is to compare the calculated GIC in a transformer with
the limits at different GIC pulse widths. A narrow GIC pulse has a higher limit than a longer duration or wider
one. If the calculated GIC and assumed pulse width falls below the appropriate pulse width curve, then the
transformer is within its capability.
To use these curves, it is necessary to estimate an equivalent square pulse that matches the waveform of
GIC(t), generally at a GIC(t) peak. Figure 15 shows a close‐up of the GIC near its highest peak superimposed
to a 255 Amperes per phase, 2 minute pulse at 100% loading from Figure 13. Since a narrow 2‐minute pulse
is not representative of GIC(t) in this case, a 5 minute pulse with an amplitude of 180 A/phase at 100%
loading has been superimposed on Figure 16. It should be noted that a 255 A/phase, 2 minute pulse is
equivalent to a 180 A/phase 5 minute pulse from the point of view of transformer capability. Deciding what
GIC pulse is equivalent to the portion of GIC(t) under consideration is a matter of engineering judgment.
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Figure 15: Close-up of GIC(t) and a 2 minute 255 A/phase GIC pulse at full load
Figure 16: Close‐up of GIC(t) and a Five Minute 180 A/phase GIC Pulse at Full Load
When using a capability curve, it should be understood that the curve is derived assuming that there is no
hot spot heating due to prior GIC at the time the GIC pulse occurs (only an initial temperature due to
loading). Therefore, in addition to estimating the equivalent pulse that matches GIC(t), prior metallic hot
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spot heating must be accounted for. From these considerations, it is unclear whether the capability curves
would be exceeded at full load with a 180C threshold in this example.
At 70% loading, the two and five minute pulses from Figure 13 would have amplitudes of 310 and 225
A/phase, respectively. The 5 minute pulse is illustrated in Figure 17. In this case, judgment is also required
to assess if the GIC(t) is within the capability curve for 70% loading. In general, capability curves are easier
to use when GIC(t) is substantially above, or clearly below the GIC thresholds for a given pulse duration.
If a conservative threshold of 160C were used to account for the age and condition of the transformer,
then a new set of capability curves would be required.
Figure 17: Close-up of GIC(t) and a 5 Minute 225 A/phase GIC Pulse Assuming 70% Load
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References
[1] "IEEE Guide for Loading Mineral‐Oil‐Immersed Transformers and Step‐Voltage Regulators." IEEE Std
C57.91‐2011 (Revision of IEEE Std C57.91‐1995). March 7, 2012.
[2] “Application Guide: Computing Geomagnetically‐Induced Current in the Bulk‐Power System,” NERC.
December 2013. Available at: http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20
Task%20Force%20GMDTF%202013/GIC%20Application%20Guide%202013_approved.pdf.
[3] “Screening Criterion for Transformer Thermal Impact Assessment.” Developed by the Project 2013‐
03 (Geomagnetic Disturbance) standard drafting team. October 2017. Available at: http://www.
nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[4] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.”
IEEE Std C57.163‐2015. October 26, 2015.
[5] Girgis, R.; Vedante, K. “Methodology for evaluating the impact of GIC and GIC capability of power
transformer designs.” IEEE Power and Energy Society 2013 General Meeting Proceedings.
Vancouver, Canada.
[6] Marti, L.; Rezaei‐Zare, A.; and Narang, A. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents." IEEE Transactions on Power Delivery, Vol.28, No.1. pp 320‐327.
January 2013.
[7] “Benchmark Geomagnetic Disturbance Event Description” white paper. Developed by the Project
2013‐03 (Geomagnetic Disturbance) standard drafting team. May 2016. Available at: http://
www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[8] “Supplemental Geomagnetic Disturbance Event Description” white paper. Developed by the Project
2013‐03 (Geomagnetic Disturbance) standard drafting team. October 2017. Available at: http://
www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[9] Lahtinen, M; and Elovaara, J. “GIC occurrences and GIC test for 400 kV system transformer.” IEEE
Transactions on Power Delivery, Vol. 17, No. 2. pp 555‐561. April 2002.
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Transformer Thermal Impact Assessment
White Paper
TPL-007-2 ̶– Transmission System Planned Performance for
Geomagnetic Disturbance Events
Background
Proposed TPL‐007‐2 includes requirements for entities to perform two types of geomagnetic disturbance
(GMD) Vulnerability Assessments to evaluate the potential impacts of GMD events on the Bulk Electric
System (BES):
The benchmark GMD Vulnerability Assessment is based on the benchmark GMD event associated
with TPL‐007‐1 which was approved by the Federal Energy Regulatory Commission (FERC) in Order
No. 830 in September 2016. The benchmark GMD event is derived from spatially‐averaged
geoelectric field values to address potential wide‐area effects that could be caused by a severe 1‐in‐
100 year GMD event.1
The supplemental GMD Vulnerability Assessment, based on the supplemental GMD event, is used
by entities to evaluate localized peaks in geomagnetic field during a severe GMD event that "could
potentially affect the reliable operation of the Bulk‐Power System."2 Localized enhancements of
geomagnetic field can result in geoelectric field values above the spatially‐averaged benchmark in
a local area.
The standard requires transformer thermal impact assessments to be performed on BES power
transformers with high side, wye‐grounded windings with terminal voltage greater than 200 kV. Large
power transformers connected to the extra‐high voltage (EHV) transmission system can experience both
winding and structural hot spot heating as a result of GMD events. TPL‐007‐2 requires owners of such BES
transformers to conduct thermal analyses to determine if the BES transformers will be able to withstand
the thermal transient effects associated with the GMD events. BES Transformerstransformers must
undergo a thermal impact assessment if the maximum effective geomagnetically‐induced current (GIC) in
the transformer is equal to or greater than:3
75 A per phase for the benchmark GMD event
85 A per phase for the supplemental GMD event
This white paper discusses methods that can be employed to conduct transformer thermal impact
assessments, including example calculations. The first version of the white paper was developed by the
Project 2013‐03 GMD Standards Drafting Team (SDT) for TPL‐007‐1 and was endorsed by the Electric
1 See Benchmark Geomagnetic Disturbance Event Description white paper, May 12, 2016. Filed by NERC in RM15‐11 on June 28, 2016.
2 See Order No. 830 P. 47. On September 22, 2016, FERC directed NERC to develop modifications to the benchmark GMD event, included in
TPL‐007‐1, such that assessments would not be based solely on spatially averaged data. The characteristics of a GMD event for this
assessment are in the Supplemental GMD Event Description white paper.
3 See Screening Criterion for Transformer Thermal Impact Assessment for technical justification.
Reliability Organization (ERO) as implementation guidance in October 2016. The SDT has updated the white
paper to include the supplemental GMD event that is added in TPL‐007‐2 to address directives in FERC
Order No. 830.
The primary impact of GMDs on large power transformers is a result of the quasi‐dc current that flows
through wye‐grounded transformer windings. This geomagnetically‐induced current (GIC) results in an
offset of the ac sinusoidal flux resulting in asymmetric or half‐cycle saturation (see Figure 1).
Half‐cycle saturation results in a number of known effects:
Hot spot heating of transformer windings due to harmonics and stray flux;
Hot spot heating of non‐current carrying transformer metallic members due to stray flux;
Harmonics;
Increase in reactive power absorption; and
Increase in vibration and noise level.
Figure 1: Mapping Magnetization Current to Flux through Core Excitation Characteristics
This paper focuses on hot spot heating of transformer windings and non‐current‐carrying metallic parts.
Effects such as the generation of harmonics, increase in reactive power absorption, vibration, and noise
are not within the scope of this document.
Transformer Thermal Impact Assessment: White Paper
Project 2013‐03 Geomagnetic Disturbance Mitigation | JuneOctober 2017
2
Technical Considerations
The effects of half‐cycle saturation on high‐voltage (HV) and EHV transformers, namely localized “hot spot”
heating, are relatively well understood, but are difficult to quantify. A transformer GMD impact assessment
must consider GIC amplitude, duration, and transformer physical characteristics such as design and
condition (e.g., age, gas content, and moisture in the oil). A single threshold value of GIC cannot be justified
as a “pass or fail” screening criterion where “fail” means that the transformer will suffer damage. A single
threshold value of GIC only makes sense in the context where “fail” means that a more detailed study is
required. Such a threshold would have to be technically justifiable and sufficiently low to be considered a
conservative value of GIC.
The following considerations should be taken into account when assessing the thermal susceptibility of a
transformer to half‐cycle saturation:
In the absence of manufacturer specific information, use the temperature limits for safe transformer
operation such as those suggested in the IEEE Std C57.91‐2011 (IEEE Guide for Loading Mineral‐oil‐
immersed Transformers and Step‐voltage Regulators) for hot spot heating during short‐term
emergency operation [1]. This standard does not suggest that exceeding these limits will result in
transformer failure, but rather that it will result in additional aging of cellulose in the paper‐oil
insulation and the potential for the generation of gas bubbles in the bulk oil. Thus, from the point
of view of evaluating possible transformer damage due to increased hot spot heating, these
thresholds can be considered conservative for a transformer in good operational condition.
The worst case temperature rise for winding and metallic part (e.g., tie plate) heating should be
estimated taking into consideration the construction characteristics of the transformer as they
pertain to dc flux offset in the core (e.g., single‐phase, shell, 5 and 3‐leg three‐phase construction).
Bulk oil temperature due to ambient temperature and transformer loading must be added to the
incremental temperature rise caused by hot spot heating. For planning purposes, maximum ambient
and loading temperature should be used unless there is a technically justified reason to do
otherwise.
The time series or “waveform” of the reference GMD event in terms of peak amplitude, duration,
and frequency of the geoelectric field has an important effect on hot spot heating. Winding and
metallic part hot spot heating have different thermal time constants, and their temperature rise will
be different if the GIC currents are sustained for 2, 10, or 30 minutes for a given GIC peak amplitude.
The “effective” GIC in autotransformers (reflecting the different GIC ampere‐turns in the common
and the series windings) must be used in the assessment. The effective current Idc,eq in an
autotransformer is defined by [2].
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,
⁄3
⁄
(1)
where
IH is the dc current in the high voltage winding;
IN is the neutral dc current;
VH is the root mean square (rms) rated voltage at HV terminals; and
VX is the rms rated voltage at the LV terminals.
Transformer Thermal Impact Assessment Process
A simplified thermal assessment may be based on the appropriate tables from the “Screening Criterion for
Transformer Thermal Impact Assessment” white paper [3].4 Each table below provides the peak metallic
hot spot temperatures that can be reached for the given GMD event using conservative thermal models.
To use each table, one must select the bulk oil temperature and the threshold for metallic hot spot heating,
for instance, from reference [1] after allowing for possible de‐rating due to transformer condition. If the
effective GIC results in higher than threshold temperatures, then the use of a detailed thermal assessment
as described below should be carried out.5
Table 1: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Benchmark GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
(A/phase)
Temperature (C )
Temperature (C )
0
80
100
182
10
107
110
186
20
128
120
190
30
139
130
193
40
148
140
204
50
157
150
213
60
169
160
221
70
170
170
230
75
172
180
234
80
175
190
241
90
179
200
247
4 Table 1 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound temperatures for the
benchmark GMD event. Table 2 in the Screening Criterion for Transformer Thermal Impact Assessment white paper provides upper bound
temperatures for the supplemental GMD event.
5 Effective GIC in the table is the peak GIC(t) for the GMD event being assessed. Peak GIC(t) is not steady‐state GIC.
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Table 2: Upper Bound of Peak Metallic Hot Spot Temperatures Calculated
Using the Supplemental GMD Event
Effective GIC Metallic hot spot
Effective GIC
Metallic hot spot
(A/phase)
Temperature
(A/phase)
Temperature
(°(C)
(°(C)
0
80
120
188
10
107
130
191
20
124
140
194
30
137
150
198
40
147
160
203
50
156
170
209
60
161
180
214
70
162
190
229
75
165
200
237
80
169
220
248
85
172
230
253
90
177
250
276
100
181
275
298
110
185
300
316
Two different ways to carry out a detailed thermal impact assessment are discussed below. In addition,
other approaches and models approved by international standard‐setting organizations such as the
Institute of Electrical and Electronic Engineers (IEEE) or International Council on Large Electric Systems
(CIGRE) may also provide technically justified methods for performing thermal assessments.6 All thermal
assessment methods should be demonstrably equivalent to assessments that use the GMD events
associated with TPL‐007‐2.
1. Transformer manufacturer GIC capability curves. These curves relate permissible peak GIC (obtained
by the user from a steady‐state GIC calculation) and loading, for a specific transformer. An example
of manufacturer capability curves is provided in Figure 2. Presentation details vary between
manufacturers, and limited information is available regarding the assumptions used to generate
these curves, in particular, the assumed waveshape or duration of the effective GIC. Some
manufacturers assume that the waveform of the GIC in the transformer windings is a square pulse
of 2, 10, or 30 minutes in duration. In the case of the transformer capability curve shown in Figure
2, a square pulse of 900 A/phase with a duration of 2 minutes would cause the Flitch plate hot spot
to reach a temperature of 180°C at full load [5]. While GIC capability curves are relatively simple to
use, an amount of engineering judgment is necessary to ascertain which portion of a GIC waveform
is equivalent to, for example, a 2 minute pulse. Also, manufacturers generally maintain that in the
absence of transformer standards defining thermal duty due to GIC, such capability curves must be
developed for every transformer design and vintage.
6 For example, C57.163‐2015 – IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances. [4]
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100
Flitch Plate Temp = 180 C for 2 Minutes
90
Flitch Plate Temp = 160 C for 30 Minutes
% MVA Rating
80
70
60
50
40
30
600
800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000
GIC, Amps/Phase
Figure 2: Sample GIC Manufacturer Capability Curve of a Large Single-Phase Transformer
Design using the Flitch Plate Temperature Criteria [5]
2. Thermal response simulation.7 The input to this type of simulation is the time series or waveform of
effective GIC flowing through a transformer (taking into account the actual configuration of the
system), and the result of the simulation is the hot spot temperature (winding or metallic part) time
sequence for a given transformer. An example of GIC input and hotspot temperature time series
values from [6] are shown in Figure 3. The hot spot thermal transfer functions can be obtained from
measurements or calculations provided by transformer manufacturers. Conservative default values
can be used (e.g., those provided in [6]) when specific data are not available. Hot spot temperature
thresholds shown in Figure 3 are consistent with IEEE Std C57.91‐2011 emergency loading hot spot
limits. Emergency loading time limit is usually 30 minutes.
7 Technical details of this methodology can be found in [6].
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Figure 3: Sample Tie Plate Temperature Calculation
Blue trace is incremental temperature and red trace is the magnitude of the GIC/phase [6]
It is important to reiterate that the characteristics of the time sequence or “waveform” are very important
in the assessment of the thermal impact of GIC on transformers. Transformer hot spot heating is not
instantaneous. The thermal time constants of transformer windings and metallic parts are typically on the
order of minutes to tens of minutes; therefore, hot spot temperatures are heavily dependent on GIC history
and rise time, amplitude and duration of GIC in the transformer windings, bulk oil temperature due to
loading, ambient temperature and cooling mode.
Calculation of the GIC Waveform for a Transformer
The following procedure can be used to generate time series GIC data (i.e., GIC(t)) using a software program
capable of computing GIC in the steady‐state. The steps are as follows:
1. Calculate contribution of GIC due to eastward and northward geoelectric fields for the transformer
under consideration; and
2. Scale the GIC contribution according to the reference geoelectric field time series to produce the
GIC time series for the transformer under consideration.
Most available GIC–capable software packages can calculate GIC in steady‐state in a transformer assuming
a uniform eastward geoelectric field of 1 V/km (GICE) while the northward geoelectric field is zero. Similarly,
GICN can be obtained for a uniform northward geoelectric field of 1 V/km while the eastward geoelectric
field is zero. GICE and GICN are the normalized GIC contributions for the transformer under consideration.
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If the earth conductivity is assumed to be uniform (or laterally uniform) in the transmission system of
interest, then the transformer GIC (in A/phase) for any value of EE(t) and EN(t) can be calculated using (2)
[2].
|
|
sin
cos
(2)
where,
|
|
tan
(3)
(4)
(5)
GICN is the effective GIC due to a northward geoelectric field of 1 V/km, and GICE is the effective GIC due to
an eastward geoelectric field of 1 V/km. The units for GICN and GICE are A/phase per V/km)).
The geoelectric field time series EN(t) and EE(t) is obtained, for instance, from the reference geomagnetic
field time series (from [7] and/or [8]) after the appropriate geomagnetic latitude scaling factor is applied.8
The reference geoelectric field time series is calculated using the reference earth model. When using this
geoelectric field time series where a different earth model is applicable, it should be scaled with the
appropriate conductivity scaling factor .9 Alternatively, the geoelectric field can be calculated from the
reference geomagnetic field time series after the appropriate geomagnetic latitude scaling factor is
applied and the appropriate earth model is used. In such case, the conductivity scaling factor is not applied
because it is already accounted for by the use of the appropriate earth model.
Applying (5) to each point in EN(t) and EE(t) results in GIC(t).
GIC(t) Calculation Example
Let us assume that from the steady‐state solution, the effective GIC in this transformer is GICE = ‐20 A/phase
if EN=0, EE=1 V/km and GICN = 26 A/phase if EN=1 V/km, EE=0. Let us also assume the geomagnetic field time
8 The geomagnetic factor is described in [2] and is used to scale the geomagnetic field according to geomagnetic latitude. The lower the
geomagnetic latitude (closer to the equator), the lower the amplitude of the geomagnetic field.
9 The conductivity scaling factor is described in [2], and is used to scale the geoelectric field according to the conductivity of different
physiographic regions. Lower conductivity results in higher scaling factors.
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series corresponds to a geomagnetic latitude where = 1 and that the earth conductivity corresponds to
the reference earth model in [7]. The resulting geoelectric field time series is shown in Figure 4. Therefore:
⁄
20
26
⁄
(6)
(7)
The resulting GIC waveform GIC(t) is shown in Figures 5 and 6 and can subsequently be used for thermal
analysis.
It should be emphasized that even for the same reference event, the GIC(t) waveform in every transformer
will be different, depending on the location within the system and the number and orientation of the
circuits connecting to the transformer station. Assuming a single generic GIC(t) waveform to test all
transformers is incorrect.
Figure 4: Calculated Geoelectric Field EN(t) and EE(t) Assuming =1 and =1
(Reference Earth Model)
Zoom area for subsequent graphs is highlighted
Dashed lines approximately show the close-up area for subsequent Figures
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Figure 5: Calculated GIC(t) Assuming =1 and =1
Reference Earth Model
Figure 6: Calculated Magnitude of GIC(t) Assuming =1 and =1
Reference Earth Model
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Transformer Thermal Assessment Examples
There are two basic ways to carry out a transformer thermal analysis once the GIC time series GIC(t) is
known for a given transformer: 1) calculating the thermal response as a function of time; and 2) using
manufacturer’s capability curves.
Example 1: Calculating thermal response as a function of time using a thermal response tool
The thermal step response of the transformer can be obtained for both winding and metallic part hot spots
from: 1) measurements; 2) manufacturer’s calculations; or 3) generic published values. Figure 7 shows the
measured metallic hot spot thermal response to a dc step of 16.67 A/phase of the top yoke clamp from [9]
that will be used in this example. Figure 8 shows the measured incremental temperature rise (asymptotic
response) of the same hot spot to long duration GIC steps.10
Figure 7: Thermal Step Response to a 16.67 Amperes per Phase dc Step
Metallic hot spot heating
10 Heating of bulk oil due to the hot spot temperature increase is not included in the asymptotic response because the time constant of bulk
oil heating is at least an order of magnitude larger than the time constants of hot spot heating.
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Figure 8: Asymptotic Thermal Step Response
Metallic hot spot heating
The step response in Figure 7 was obtained from the first GIC step of the tests carried out in [6]. The
asymptotic thermal response in Figure 8 was obtained from the final or near‐final temperature values after
each subsequent GIC step. Figure 9 shows a comparison between measured temperatures and the
calculated temperatures using the thermal response model used in the rest of this discussion.
Figure 9: Comparison of measured temperatures (red) and simulation results (blue)
Injected current is represented by magenta
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To obtain the thermal response of the transformer to a GIC waveform such as the one in Figure 6, a thermal
response model is required. To create a thermal response model, the measured or manufacturer‐calculated
transformer thermal step responses (winding and metallic part) for various GIC levels are required. The
GIC(t) time series or waveform is then applied to the thermal model to obtain the incremental temperature
rise as a function of time (t) for the GIC(t) waveform. The total temperature is calculated by adding the oil
temperature, for example, at full load.
Figure 10 illustrates the calculated GIC(t) and the corresponding metallic hot spot temperature time series
(t). Figure 11 illustrates a close‐up view of the peak transformer temperatures calculated in this example.
Figure 10: Magnitude of GIC(t) and Metallic Hot Spot Temperature (t) Assuming Full Load
Oil Temperature of 85.3C (40C ambient)
Dashed lines approximately show the close-up area for subsequent figures
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Figure 11: Close-up of Metallic Hot Spot Temperature Assuming a Full Load
Blue trace is (t) Red trace is GIC(t)
In this example, the IEEE Std C57.91‐2011 emergency loading hot spot threshold of 200C for metallic hot
spot heating is not exceeded. Peak temperature is 186C. The IEEE standard is silent as to whether the
temperature can be higher than 200C for less than 30 minutes. Manufacturers can provide guidance on
individual transformer capability.
It is not unusual to use a lower temperature threshold of 180C to account for calculation and data margins,
as well as transformer age and condition. Figure 11 shows that 180C will be exceeded for 5 minutes.
At 75% loading, the initial temperature is 64.6°C rather than 85.3°C, and the hot spot temperature peak
is 165C, well below the 180C threshold (see Figure 12).
If a conservative threshold of 160C were used to account for the age and condition of the transformer,
then the full load limits would be exceeded for approximately 22 minutes.
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Figure 12: Close-up of Metallic Hot Spot Temperature Assuming a 75% Load
Oil temperature of 64.5C
Example 2: Using a Manufacturer’s Capability Curves
The capability curves used in this example are shown in Figure 13. To maintain consistency with the previous
example, these particular capability curves have been reconstructed from the thermal step response shown
in Figures 7 and 8, and the simplified loading curve shown in Figure 14 (calculated using formulas from IEEE
Std C57.91‐2011).
Figure 13: Capability Curve of a Transformer Based on the Thermal Response Shown in
Figures 8 and 9
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Figure 14: Simplified Loading Curve Assuming 40C Ambient Temperature
The basic notion behind the use of capability curves is to compare the calculated GIC in a transformer with
the limits at different GIC pulse widths. A narrow GIC pulse has a higher limit than a longer duration or wider
one. If the calculated GIC and assumed pulse width falls below the appropriate pulse width curve, then the
transformer is within its capability.
To use these curves, it is necessary to estimate an equivalent square pulse that matches the waveform of
GIC(t), generally at a GIC(t) peak. Figure 15 shows a close‐up of the GIC near its highest peak superimposed
to a 255 Amperes per phase, 2 minute pulse at 100% loading from Figure 13. Since a narrow 2‐minute pulse
is not representative of GIC(t) in this case, a 5 minute pulse with an amplitude of 180 A/phase at 100%
loading has been superimposed on Figure 16. It should be noted that a 255 A/phase, 2 minute pulse is
equivalent to a 180 A/phase 5 minute pulse from the point of view of transformer capability. Deciding what
GIC pulse is equivalent to the portion of GIC(t) under consideration is a matter of engineering judgment.
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Figure 15: Close-up of GIC(t) and a 2 minute 255 A/phase GIC pulse at full load
Figure 16: Close‐up of GIC(t) and a Five Minute 180 A/phase GIC Pulse at Full Load
When using a capability curve, it should be understood that the curve is derived assuming that there is no
hot spot heating due to prior GIC at the time the GIC pulse occurs (only an initial temperature due to
loading). Therefore, in addition to estimating the equivalent pulse that matches GIC(t), prior metallic hot
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spot heating must be accounted for. From these considerations, it is unclear whether the capability curves
would be exceeded at full load with a 180°C threshold in this example.
At 70% loading, the two and five minute pulses from Figure 13 would have amplitudes of 310 and 225
A/phase, respectively. The 5 minute pulse is illustrated in Figure 17. In this case, judgment is also required
to assess if the GIC(t) is within the capability curve for 70% loading. In general, capability curves are easier
to use when GIC(t) is substantially above, or clearly below the GIC thresholds for a given pulse duration.
If a conservative threshold of 160C were used to account for the age and condition of the transformer,
then a new set of capability curves would be required.
Figure 17: Close-up of GIC(t) and a 5 Minute 225 A/phase GIC Pulse Assuming 70% Load
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References
[1] "IEEE Guide for loading mineral‐oil‐immersed transformersLoading Mineral‐Oil‐Immersed
Transformers and step‐voltage regulatorsStep‐Voltage Regulators." IEEE Std C57.91‐2011 (Revision
of IEEE Std C57.91‐1995). March 7, 2012.
[2] “Application Guide: Computing Geomagnetically‐Induced Current in the Bulk‐Power System,,”
NERC.
December
2013.
Available
at:
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20
Task%20Force%20GMDTF%202013/GIC%20Application%20Guide%202013_approved.pdf.
[3] “Screening Criterion for Transformer Thermal Impact Assessment”..” Developed by the Project
2013‐03 (Geomagnetic Disturbance) standard drafting team. October 2017. Available at:
http://www.
nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[4] “IEEE Guide for Establishing Power Transformer Capability while under Geomagnetic Disturbances.”
IEEE Std C57.163‐2015. October 26, 2015.
[5] Girgis, R.; Vedante, K. “Methodology for evaluating the impact of GIC and GIC capability of power
transformer designs.” IEEE PESPower and Energy Society 2013 General Meeting Proceedings.
Vancouver, Canada.
[6] Marti, L.,.; Rezaei‐Zare, A.,.; and Narang, A. "Simulation of Transformer Hotspot Heating due to
Geomagnetically Induced Currents." IEEE Transactions on Power Delivery, volVol.28, noNo.1. pp
320‐327. January 2013.
[7] “Benchmark Geomagnetic Disturbance Event Description” white paper. Developed by the Project
2013‐03 (Geomagnetic Disturbance) standard drafting team. May 2016. Available at: http://
www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[8] “Supplemental Geomagnetic Disturbance Event Description” white paper. Developed by the Project
2013‐03 (Geomagnetic Disturbance) standard drafting team. October 2017. Available at: http://
www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐Geomagnetic‐Disturbance‐Mitigation.aspx.
[9] Lahtinen, Matti. JarmoM; and Elovaara, J. “GIC occurrences and GIC test for 400 kV system
transformer”..” IEEE Transactions on Power Delivery, Vol. 17, No. 2. pp 555‐561. April 2002.
Transformer Thermal Impact Assessment: White Paper
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Violation Risk Factor and Violation Severity Level
Justifications
TPL-007-2 Transmission System Planned Performance for Geomagnetic Disturbance Events
This document provides the Standard Drafting Team’s (SDT) justification for assignment of Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs) for each requirement in TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events.
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 ERO Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project.
NERC Criteria - 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 Violation Risk Factor Guidelines
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
The Commission 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
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Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) – Consistency within a Reliability Standard
The Commission expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
The Commission 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.
NERC Criteria - 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.
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VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
High VSL
The performance or product
The performance or product
The performance or product
measured almost meets the full measured meets the majority of measured does not meet the
intent of the requirement.
the intent of the requirement.
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
FERC’s 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.
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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 Justifications – TPL-007-2, R1
Proposed VRF
Low
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report. N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard. The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with Reliability
Standard TPL‐001‐4 Requirement R7, which requires the Planning Coordinator, in conjunction with
each of its Transmission Planners, to identify each entity’s individual and joint responsibilities for
performing required studies for the Planning Assessment. Proposed TPL‐007‐2 Requirement R1
requires Planning Coordinators, in conjunction with Transmission Planners, to identify individual and
joint responsibilities for maintaining models and performing studies needed to complete the
benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in the Standard.
Guideline 4‐ Consistency with NERC Definitions of VRFs. A VRF of Lower is consistent with the NERC
VRF definition. The requirement for identifying individual and joint responsibilities of the Planning
Coordinator and each of the Transmission Planners in the Planning Coordinator’s planning area for
maintaining models, performing GMD studies, and obtaining GMD measurement data, 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, control, or restore the Bulk Electric System under conditions of a
GMD event.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
5
VRF Justifications – TPL-007-2, R1
Proposed VRF
FERC VRF G5 Discussion
Low
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. The requirement
contains one objective, therefore a single VRF is assigned.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
6
Proposed VSLs – TPL-007-2, R1
Lower
N/A
Moderate
N/A
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
High
N/A
Severe
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.
7
VSL Justifications – TPL-007-2, R1
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
The VSL is not changed in TPL‐007‐2.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
8
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
9
VRF Justifications – TPL-007-2, R2
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with the VRF for
Reliability Standard TPL‐001‐4 Requirement R1 as amended in NERC's filing dated August 29, 2014,
which requires Transmission Planners and Planning Coordinators to maintain models within its
respective planning area for performing studies needed to complete its Planning Assessment.
Proposed TPL‐007‐2, Requirement R2 requires responsible entities to maintain System models and GIC
System models of the responsible entity’s planning area for performing the studies needed to
complete benchmark and supplemental GMD Vulnerability Assessments.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. The System Models and GIC System Models serve as the foundation for all conditions
and events that are required to be studied and evaluated in the benchmark and supplemental GMD
Vulnerability Assessments. For this reason, failure to maintain models of the responsible entity’s
planning area for performing GMD studies could, under GMD conditions that are as severe as the
benchmark and supplemental GMD event, place the Bulk Electric System at an unacceptable risk of
instability, separation, or cascading failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
10
Proposed VSLs – TPL-007-2, R2
Lower
N/A
Moderate
High
Severe
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
needed to complete benchmark
and supplemental GMD
Vulnerability Assessments.
The responsible entity did not
maintain both System models
and GIC System models of the
responsible entity’s planning
area for performing the studies
needed to complete benchmark
and supplemental GMD
Vulnerability Assessments.
VSL Justifications – TPL-007-2, R2
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Two VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
11
VSL Justifications – TPL-007-2, R2
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
12
VRF Justifications – TPL-007-2, R3
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard TPL‐001‐4 Requirement R5 which requires Transmission Planners and Planning Coordinators
to have criteria for acceptable System steady state voltage limits. Proposed TPL‐007‐2 Requirement R4
requires responsible entities to have criteria for acceptable System steady state voltage performance
for its System during the benchmark GMD event; these criteria may be different from the voltage
limits determined in Reliability Standard TPL‐001‐4 Requirement R5.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to have criteria for acceptable System steady state voltage limits for its
System during a GMD planning event could 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 during an actual GMD event. However, it is unlikely that such a failure by itself would
lead to Bulk Electric System instability, separation, or cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
13
Proposed VSLs – TPL-007-2, R3
Lower
N/A
Moderate
N/A
High
N/A
Severe
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.
VSL Justifications – TPL-007-2, R3
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
14
VSL Justifications – TPL-007-2, R3
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
15
VRF Justifications – TPL-007-2, R4
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL‐001‐4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. Proposed TPL‐007‐2 Requirement R4 requires responsible entities to complete a
benchmark GMD Vulnerability Assessment to ensure the system meets performance criteria during the
benchmark GMD event.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a benchmark GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the benchmark GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
16
Proposed VSLs – TPL-007-2, R4
Lower
Moderate
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
High
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
The responsible entity
completed a benchmark GMD
completed a benchmark GMD
Vulnerability Assessment, but it Vulnerability Assessment, but it
was more than 68 calendar
was more than 64 calendar
months and less than or equal
months and less than or equal
to 68 calendar months since the to 72 calendar months since the
last benchmark GMD
last benchmark GMD
Vulnerability Assessment.
Vulnerability Assessment.
Severe
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 GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed benchmark
GMD Vulnerability Assessment.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
17
VSL Justifications – TPL-007-2, R4
NERC VSL Guidelines
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
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
18
VSL Justifications – TPL-007-2, R4
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R5
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
19
VRF Justifications – TPL-007-2, R5
Proposed VRF
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Medium
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard MOD‐032‐1 Requirement R2 which requires applicable entities to provide modeling data to
Transmission Planners and Planning Coordinators. A VRF of Medium is also consistent with Reliability
Standard IRO‐010‐2 Requirement R3 which requires entities to provide data necessary for the
Reliability Coordinator to perform its Operational Planning Analysis and Real‐time Assessments.
Proposed TPL‐007‐2 Requirement R5 requires responsible entities to provide specific geomagnetically‐
induced currents (GIC) flow information to Transmission Owners and Generator Owners for
performing transformer thermal impact assessments.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the benchmark GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
20
Proposed VSLs – TPL-007-2, R5
Lower
Moderate
High
Severe
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.
VSL Justifications – TPL-007-2, R5
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VLS is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
21
VSL Justifications – TPL-007-2, R5
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
22
VRF Justifications – TPL-007-2, R6
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard FAC‐008‐3 Requirement R6 which requires Transmission Owners and Generator Owners to
have Facility Ratings for all solely and jointly owned Facilities that are consistent with the associated
Facility Ratings methodology or documentation. Proposed TPL‐007‐2 Requirement R6 requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a benchmark transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
23
Proposed VSLs – TPL-007-2, R6
Lower
Moderate
High
Severe
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 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
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 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
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 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
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 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
24
Proposed VSLs – TPL-007-2, R6
Lower
of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
Moderate
High
Severe
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 required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
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 required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
GIC flow information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed to
include three of the required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
VSL Justifications – TPL-007-2, R6
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
25
VSL Justifications – TPL-007-2, R6
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
26
VRF Justifications – TPL-007-2, R7
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. 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. Proposed TPL‐007‐2 Requirement R7 requires responsible entities to develop a Corrective
Action Plan when results of the benchmark GMD Vulnerability Assessment indicate that the System
does not meet performance requirements. While Reliability Standard TPL‐001‐4 has a single
requirement for performing the Planning Assessment and developing the Corrective Action Plan,
proposed TPL‐007‐2 has split the requirements for performing a benchmark GMD Vulnerability
Assessment and developing the Corrective Action Plan into two separate requirements because the
transformer thermal impact assessments performed by Transmission Owners and Generator Owners
must be considered. The sequencing with separate requirements follows a logical flow of the GMD
Vulnerability Assessment process.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to develop a Corrective Action Plan that addresses issues identified in a GMD
Vulnerability Assessment could, under GMD conditions that are as severe as the benchmark GMD
event, place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading
failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
27
Proposed VSLs – TPL-007-2, R7
Lower
Moderate
High
Severe
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
have a Corrective Action Plan as
required by Requirement R7.
VSL Justifications – TPL-007-2, R7
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The proposed requirement is a significant revision to TPL‐007‐2 to address the directive for Corrective
FERC VSL G1
Action Plan deadlines contained in FERC Order No. 830. There is no prior compliance obligation related
Violation Severity Level
to the directive. However, the requirement uses the same construct for a graduated scale as TPL‐007‐1
Assignments Should Not Have
the Unintended Consequence of Requirement R7 and is similar to Reliability Standard TPL‐001‐4, Requirement R2.
Lowering the Current Level of
Compliance
NERC VSL Guidelines
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
28
VSL Justifications – TPL-007-2, R7
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
29
VRF Justifications – TPL-007-2, R8
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL‐001‐4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. The proposed requirement is also consistent with approved TPL‐007‐1
Requirement R4 (unchanged in proposed TPL‐007‐2 Requirement R4). Proposed TPL‐007‐2
Requirement R8 requires responsible entities to complete a supplemental GMD Vulnerability
Assessment to assess system performance during a supplemental GMD event.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a supplemental GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the supplemental GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures by precluding responsible entities
from considering actions to mitigate risk of Cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
30
Proposed VSLs – TPL-007-2, R8
Lower
Moderate
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 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 two of elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
High
The responsible entity's
completed supplemental GMD
Vulnerability Assessment failed
to satisfy three of the elements
listed in Requirement R8, Parts
8.1 through 8.4;
OR
The responsible entity
The responsible entity
completed a supplemental GMD completed a supplemental GMD
Vulnerability Assessment, but it Vulnerability Assessment, but it
was more than 68 calendar
was more than 64 calendar
months and less than or equal
months and less than or equal
to 68 calendar months since the to 72 calendar months since the
last supplemental GMD
last supplemental GMD
Vulnerability Assessment.
Vulnerability Assessment.
Severe
The responsible entity's
completed supplemental GMD
Vulnerability Assessment failed
to satisfy four of the 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 than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
31
VSL Justifications – TPL-007-2, R8
NERC VSL Guidelines
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
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
However, the requirement is similar to approved TPL‐007‐1, Requirement R4 (unchanged in proposed
TPL‐007‐2 Requirement R4). That requirement also has a graduated scale for VSLs.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
32
VSL Justifications – TPL-007-2, R8
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R9
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL‐007‐1 Requirement R5 (unchanged in proposed TPL‐007‐2 Requirement R5) which requires
responsible entities to provide specific geomagnetically‐induced currents (GIC) flow information to
Transmission Owners and Generator Owners for performing transformer thermal impact assessments.
FERC VRF G3 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
33
VRF Justifications – TPL-007-2, R9
Proposed VRF
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Medium
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the supplemental GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
34
Proposed VSLs – TPL-007-2, R9
Lower
Moderate
High
Severe
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.
VSL Justifications – TPL-007-2, R9
NERC VSL Guidelines
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
35
VSL Justifications – TPL-007-2, R9
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
FERC VSL G1
However, the requirement is similar to approved TPL‐007‐1, Requirement R5 (unchanged in proposed
Violation Severity Level
TPL‐007‐2 Requirement R5). That requirement also has a graduated scale for VSLs.
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
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
36
VSL Justifications – TPL-007-2, R9
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R10
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL‐007‐1 Requirement R6 (unchanged in proposed TPL‐007‐2 Requirement R6), which requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a supplemental transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
37
VRF Justifications – TPL-007-2, R10
Proposed VRF
FERC VRF G5 Discussion
Medium
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
Proposed VSLs – TPL-007-2, R10
Lower
Moderate
High
Severe
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
38
Proposed VSLs – TPL-007-2, R10
Lower
Moderate
High
Severe
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.
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
The responsible entity failed to
include one of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
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
The responsible entity failed to
include two of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
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
The responsible entity failed to
include three of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
VSL Justifications – TPL-007-2, R10
NERC VSL Guidelines
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
39
VSL Justifications – TPL-007-2, R10
There is no prior compliance obligation related to supplemental thermal impact assessment. However,
FERC VSL G1
the requirement is similar to approved TPL‐007‐1, Requirement R6 (unchanged in proposed TPL‐007‐2
Violation Severity Level
Requirement R6). That requirement also has a graduated scale for VSLs.
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
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
40
VSL Justifications – TPL-007-2, R10
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R11
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD‐032‐1 Requirement R1 and Reliability Standard IRO‐010‐2 Requirement R1.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain GIC monitor data from at least one GIC monitor located in the system
would not 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.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
41
Proposed VSLs – TPL-007-2, R11
Lower
N/A
Moderate
N/A
High
Severe
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.
VSL Justifications – TPL-007-2, R11
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
There is no prior compliance obligation for this requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
42
VSL Justifications – TPL-007-2, R11
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
43
VRF Justifications – TPL-007-2, R12
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD‐032‐1 Requirement R1 and Reliability Standard IRO‐010‐2 Requirement R1.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain geomagnetic field data for the planning area would not 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.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
44
Proposed VSLs – TPL-007-2, R12
Lower
N/A
Moderate
N/A
High
Severe
N/A
The responsible entity did not
implement a process to obtain
geomagnetic field data for its
Planning Coordinator’s planning
area.
VSL Justifications – TPL-007-2, R12
NERC VSL Guidelines
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
Guideline 2a: The Single
Violation Severity Level
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
There is no prior compliance obligation for this requirement.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
45
VSL Justifications – TPL-007-2, R12
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications | October 2017
46
Violation Risk Factor and Violation Severity Level
Justifications
TPL-007-2 Transmission System Planned Performance for Geomagnetic Disturbance Events
This document provides the Standard Drafting Team’s (SDT) justification for assignment of Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs) for each requirement in TPL‐007‐2 – Transmission System Planned Performance for Geomagnetic Disturbance Events.
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 ERO Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project.
NERC Criteria - 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 Violation Risk Factor Guidelines
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
The Commission 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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2
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) – Consistency within a Reliability Standard
The Commission expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
The Commission 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.
NERC Criteria - 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.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
High VSL
The performance or product
The performance or product
The performance or product
measured almost meets the full measured meets the majority of measured does not meet the
intent of the requirement.
the intent of the requirement.
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
FERC’s 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.
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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 Justifications – TPL-007-2, R1
Proposed VRF
Low
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report. N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard. The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with Reliability
Standard TPL‐001‐4 Requirement R7, which requires the Planning Coordinator, in conjunction with
each of its Transmission Planners, to identify each entity’s individual and joint responsibilities for
performing required studies for the Planning Assessment. Proposed TPL‐007‐2 Requirement R1
requires Planning Coordinators, in conjunction with Transmission Planners, to identify individual and
joint responsibilities for maintaining models and performing studies needed to complete the
benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in the Standard.
Guideline 4‐ Consistency with NERC Definitions of VRFs. A VRF of Lower is consistent with the NERC
VRF definition. The requirement for identifying individual and joint responsibilities of the Planning
Coordinator and each of the Transmission Planners in the Planning Coordinator’s planning area for
maintaining models, performing GMD studies, and obtaining GMD measurement data, 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, control, or restore the Bulk Electric System under conditions of a
GMD event.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
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VRF Justifications – TPL-007-2, R1
Proposed VRF
FERC VRF G5 Discussion
Low
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. The requirement
contains one objective, therefore a single VRF is assigned.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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Proposed VSLs – TPL-007-2, R1
Lower
N/A
Moderate
N/A
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
High
N/A
Severe
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 the Standard. this standard.
7
VSL Justifications – TPL-007-2, R1
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
The VSL is not changed in TPL‐007‐2.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL is not based on a cumulative number of violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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9
VRF Justifications – TPL-007-2, R2
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with the VRF for
Reliability Standard TPL‐001‐4 Requirement R1 as amended in NERC's filing dated August 29, 2014,
which requires Transmission Planners and Planning Coordinators to maintain models within its
respective planning area for performing studies needed to complete its Planning Assessment.
Proposed TPL‐007‐2, Requirement R2 requires responsible entities to maintain System models and GIC
System models of the responsible entity’s planning area for performing the studies needed to
complete benchmark and supplemental GMD Vulnerability Assessments.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. The System Models and GIC System Models serve as the foundation for all conditions
and events that are required to be studied and evaluated in the benchmark and supplemental GMD
Vulnerability Assessments. For this reason, failure to maintain models of the responsible entity’s
planning area for performing GMD studies could, under GMD conditions that are as severe as the
benchmark and supplemental GMD event, place the Bulk Electric System at an unacceptable risk of
instability, separation, or cascading failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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Proposed VSLs – TPL-007-2, R2
Lower
N/A
Moderate
High
Severe
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 study or
studies or studies needed to
complete benchmark and
supplemental GMD Vulnerability
Assessments.
The responsible entity did not
maintain both System models
and GIC System models of the
responsible entity’s planning
area for performing the study or
studies or studies needed to
complete benchmark and
supplemental GMD Vulnerability
Assessments.
VSL Justifications – TPL-007-2, R2
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Two VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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VSL Justifications – TPL-007-2, R2
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
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VRF Justifications – TPL-007-2, R3
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard TPL‐001‐4 Requirement R5 which requires Transmission Planners and Planning Coordinators
to have criteria for acceptable System steady state voltage limits. Proposed TPL‐007‐2 Requirement R4
requires responsible entities to have criteria for acceptable System steady state voltage performance
for its System during the benchmark GMD event; these criteria may be different from the voltage
limits determined in Reliability Standard TPL‐001‐4 Requirement R5.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to have criteria for acceptable System steady state voltage limits for its
System during a GMD planning event could 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 during an actual GMD event. However, it is unlikely that such a failure by itself would
lead to Bulk Electric System instability, separation, or cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
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Proposed VSLs – TPL-007-2, R3
Lower
N/A
Moderate
N/A
High
N/A
Severe
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.
VSL Justifications – TPL-007-2, R3
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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14
VSL Justifications – TPL-007-2, R3
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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15
VRF Justifications – TPL-007-2, R4
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL‐001‐4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. Proposed TPL‐007‐2 Requirement R4 requires responsible entities to complete a
benchmark GMD Vulnerability Assessment to ensure the system meets performance criteria during the
benchmark GMD event.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a benchmark GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the benchmark GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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16
Proposed VSLs – TPL-007-2, R4
Lower
Moderate
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
High
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
The responsible entity
completed a benchmark GMD
completed a benchmark GMD
Vulnerability Assessment, but it Vulnerability Assessment, but it
was more than 68 calendar
was more than 64 calendar
months and less than or equal
months and less than or equal
to 68 calendar months since the to 72 calendar months since the
last benchmark GMD
last benchmark GMD
Vulnerability Assessment.
Vulnerability Assessment.
Severe
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 GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed benchmark
GMD Vulnerability Assessment.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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17
VSL Justifications – TPL-007-2, R4
NERC VSL Guidelines
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
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
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VSL Justifications – TPL-007-2, R4
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R5
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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19
VRF Justifications – TPL-007-2, R5
Proposed VRF
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Medium
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard MOD‐032‐1 Requirement R2 which requires applicable entities to provide modeling data to
Transmission Planners and Planning Coordinators. A VRF of Medium is also consistent with Reliability
Standard IRO‐010‐2 Requirement R3 which requires entities to provide data necessary for the
Reliability Coordinator to perform its Operational Planning Analysis and Real‐time Assessments.
Proposed TPL‐007‐2 Requirement R5 requires responsible entities to provide specific geomagnetically‐
induced currents (GIC) flow information to Transmission Owners and Generator Owners for
performing transformer thermal impact assessments.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the benchmark GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
20
Proposed VSLs – TPL-007-2, R5
Lower
Moderate
High
Severe
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.
VSL Justifications – TPL-007-2, R5
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VLS is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
21
VSL Justifications – TPL-007-2, R5
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
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22
VRF Justifications – TPL-007-2, R6
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with Reliability
Standard FAC‐008‐3 Requirement R6 which requires Transmission Owners and Generator Owners to
have Facility Ratings for all solely and jointly owned Facilities that are consistent with the associated
Facility Ratings methodology or documentation. Proposed TPL‐007‐2 Requirement R6 requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a benchmark transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
23
Proposed VSLs – TPL-007-2, R6
Lower
Moderate
High
Severe
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 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
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 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
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 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
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 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
24
Proposed VSLs – TPL-007-2, R6
Lower
of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
Moderate
High
Severe
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 required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
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 required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
GIC flow information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed to
include three of the required
elements as listed in
Requirement R6, Parts 6.1
through 6.3.
VSL Justifications – TPL-007-2, R6
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The VSL is not changed in TPL‐007‐2.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
25
VSL Justifications – TPL-007-2, R6
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
26
VRF Justifications – TPL-007-2, R7
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. 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. Proposed TPL‐007‐2 Requirement R7 requires responsible entities to develop a Corrective
Action Plan when results of the benchmark GMD Vulnerability Assessment indicate that the System
does not meet performance requirements. While Reliability Standard TPL‐001‐4 has a single
requirement for performing the Planning Assessment and developing the Corrective Action Plan,
proposed TPL‐007‐2 has split the requirements for performing a benchmark GMD Vulnerability
Assessment and developing the Corrective Action Plan into two separate requirements because the
transformer thermal impact assessments performed by Transmission Owners and Generator Owners
must be considered. The sequencing with separate requirements follows a logical flow of the GMD
Vulnerability Assessment process.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to develop a Corrective Action Plan that addresses issues identified in a GMD
Vulnerability Assessment could, under GMD conditions that are as severe as the benchmark GMD
event, place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading
failures.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
27
Proposed VSLs – TPL-007-2, R7
Lower
Moderate
High
Severe
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
have a Corrective Action Plan as
required by Requirement R7.
VSL Justifications – TPL-007-2, R7
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
The proposed requirement is a significant revision to TPL‐007‐2 to address the directive for Corrective
FERC VSL G1
Action Plan deadlines contained in FERC Order No. 830. There is no prior compliance obligation related
Violation Severity Level
to the directive. However, the requirement uses the same construct for a graduated scale as TPL‐007‐1
Assignments Should Not Have
the Unintended Consequence of Requirement R7 and is similar to Reliability Standard TPL‐001‐4, Requirement R2.
Lowering the Current Level of
Compliance
NERC VSL Guidelines
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
28
VSL Justifications – TPL-007-2, R7
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
29
VRF Justifications – TPL-007-2, R8
Proposed VRF
High
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of High is consistent with Reliability
Standard TPL‐001‐4 Requirement R2 which requires Transmission Planners and Planning Coordinators
to prepare an annual Planning Assessment to ensure its portion of the Bulk Electric System meets
performance criteria. The proposed requirement is also consistent with approved TPL‐007‐1
Requirement R4 (unchanged in proposed TPL‐007‐2 Requirement R4). Proposed TPL‐007‐2
Requirement R8 requires responsible entities to complete a supplemental GMD Vulnerability
Assessment to assess system performance during a supplemental GMD event.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of High is consistent with the NERC
VRF Definition. Failure to complete a supplemental GMD Vulnerability Assessment could, under GMD
conditions that are as severe as the supplemental GMD event, place the Bulk Electric System at an
unacceptable risk of instability, separation, or cascading failures by precluding responsible entities
from considering actions to mitigate risk of Cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
30
Proposed VSLs – TPL-007-2, R8
Lower
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 than 60 calendar
months and less than or equal
to 64 calendar months since the
last supplemental GMD
Vulnerability Assessment;
Moderate
High
The responsible entity's
completed supplemental GMD
Vulnerability Assessment failed
to satisfy three of the elements
listed in Requirement R8, Parts
8.1 through 8.4;
OR
The responsible entity
The responsible entity
completed a supplemental GMD completed a supplemental GMD
Vulnerability Assessment, but it Vulnerability Assessment, but it
was more than 68 calendar
was more than 64 calendar
months and less than or equal
months and less than or equal
to 68 calendar months since the to 72 calendar months since the
last supplemental GMD
last supplemental GMD
Vulnerability Assessment.
Vulnerability Assessment.
The responsible entity's
completed supplemental GMD
Vulnerability Assessment failed
to satisfy two of elements listed
in Requirement R8, Parts 8.1
through 8.4;
OR
OR
.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;
Severe
The responsible entity's
completed supplemental GMD
Vulnerability Assessment failed
to satisfy four of the 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 than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
31
VSL Justifications – TPL-007-2, R8
NERC VSL Guidelines
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
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
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
However, the requirement is similar to approved TPL‐007‐1, Requirement R4 (unchanged in proposed
TPL‐007‐2 Requirement R4). That requirement also has a graduated scale for VSLs.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
32
VSL Justifications – TPL-007-2, R8
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R9
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL‐007‐1 Requirement R5 (unchanged in proposed TPL‐007‐2 Requirement R5) which requires
responsible entities to provide specific geomagnetically‐induced currents (GIC) flow information to
Transmission Owners and Generator Owners for performing transformer thermal impact assessments.
FERC VRF G3 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
33
VRF Justifications – TPL-007-2, R9
Proposed VRF
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Medium
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to provide GIC flow information for the supplemental GMD event could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
34
Proposed VSLs – TPL-007-2, R9
Lower
Moderate
High
Severe
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.
VSL Justifications – TPL-007-2, R9
NERC VSL Guidelines
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
35
VSL Justifications – TPL-007-2, R9
There is no prior compliance obligation related to supplemental GMD Vulnerability Assessment.
FERC VSL G1
However, the requirement is similar to approved TPL‐007‐1, Requirement R5 (unchanged in proposed
Violation Severity Level
TPL‐007‐2 Requirement R5). That requirement also has a graduated scale for VSLs.
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
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
36
VSL Justifications – TPL-007-2, R9
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R10
Proposed VRF
Medium
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Medium is consistent with approved
TPL‐007‐1 Requirement R6 (unchanged in proposed TPL‐007‐2 Requirement R6), which requires
responsible entities to conduct a benchmark thermal impact assessment for solely and jointly owned
applicable transformers and provide results including suggested actions to mitigate identified impacts
to planning entities.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Medium is consistent with the
NERC VRF Definition. Failure to conduct a supplemental transformer thermal impact assessment could
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 during a GMD event. However, it is
unlikely that such a failure by itself would lead to Bulk Electric System instability, separation, or
cascading.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
37
VRF Justifications – TPL-007-2, R10
Proposed VRF
FERC VRF G5 Discussion
Medium
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
Proposed VSLs – TPL-007-2, R10
Lower
Moderate
High
Severe
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
The responsible entity failed to
conduct a supplemental thermal
impact assessment 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
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
38
Proposed VSLs – TPL-007-2, R10
Lower
Moderate
High
Severe
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.
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
The responsible entity failed to
include one of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
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
The responsible entity failed to
include two of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
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
The responsible entity failed to
include three of the required
elements as listed in
Requirement R10, Parts 10.1
through 10.3.
VSL Justifications – TPL-007-2, R10
NERC VSL Guidelines
Consistent with NERC's VSL Guidelines. The requirement may be described by elements or quantities
to evaluate degrees of compliance. Four VSLs are specified for a graduated scale.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
39
VSL Justifications – TPL-007-2, R10
There is no prior compliance obligation related to supplemental thermal impact assessment. However,
FERC VSL G1
the requirement is similar to approved TPL‐007‐1, Requirement R6 (unchanged in proposed TPL‐007‐2
Violation Severity Level
Requirement R6). That requirement also has a graduated scale for VSLs.
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
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is not binary.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
40
VSL Justifications – TPL-007-2, R10
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF Justifications – TPL-007-2, R11
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD‐032‐1 Requirement R1 and Reliability Standard IRO‐010‐2 Requirement R1.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain GIC monitor data from at least one GIC monitor located in the system
would not 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.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
41
Proposed VSLs – TPL-007-2, R11
Lower
N/A
Moderate
N/A
High
Severe
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.
VSL Justifications – TPL-007-2, R11
NERC VSL Guidelines
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
Compliance
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
There is no prior compliance obligation for this requirement.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
42
VSL Justifications – TPL-007-2, R11
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
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
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
43
VRF Justifications – TPL-007-2, R12
Proposed VRF
Lower
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard: The requirement has no sub‐requirements so a
single VRF was assigned.
Guideline 3‐ Consistency among Reliability Standards. A VRF of Lower is consistent with approved
Reliability Standards requiring entities to implement processes to obtain data. These include Reliability
Standard MOD‐032‐1 Requirement R1 and Reliability Standard IRO‐010‐2 Requirement R1.
Guideline 4‐ Consistency with NERC Definitions of VRFs. The VRF of Lower is consistent with the NERC
VRF Definition. Failure to obtain geomagnetic field data for the planning area would not 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.
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation. This requirement
does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability objective.
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
44
Proposed VSLs – TPL-007-2, R12
Lower
N/A
Moderate
N/A
High
Severe
N/A
The responsible entity did not
implement a process to obtain
geomagnetic field data for its
Planning Coordinator’s planning
area.
VSL Justifications – TPL-007-2, R12
NERC VSL Guidelines
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
Guideline 2a: The Single
Violation Severity Level
Consistent with NERC's VSL Guidelines. The requirement does not have elements or quantities to
evaluate degrees of compliance. A VSL of Severe is assigned for non‐compliance.
There is no prior compliance obligation for this requirement.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL is binary and assigned a Severe VSL.
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
45
VSL Justifications – TPL-007-2, R12
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL is worded consistently with the corresponding requirement.
The proposed VSL is not based on a cumulative number of violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
TPL‐007‐2 Transmission System Planned Performance for Geomagnetic Disturbance Events
VRF and VSL Justifications – June 8,| October 2017
46
Consideration of Directives
Reliability Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events
Order No. 830, 156 FERC ¶ 61,215 (Sep. 22, 2016)
approving Reliability Standard TPL‐007‐1
Consideration of Directives
# P
Directive/Guidance
Resolution
1) PP 44
47‐49
MODIFY THE BENCHMARK GMD EVENT re SPATIAL AVERAGING
P44: “[T]he Commission, as proposed in the NOPR, directs NERC to
develop revisions to the benchmark GMD event definition so that the
reference peak geoelectric field amplitude component is not based
solely on spatially‐averaged data.”
P47: “Without prejudging how NERC proposes to address the
Commission’s directive, NERC’s response to this directive should
satisfy the NOPR’s concern that reliance on spatially‐averaged data
alone does not address localized peaks that could potentially affect
the reliable operation of the Bulk‐Power System.”
P48: “NERC could revise [the standard] to apply a higher reference
peak geoelectric field amplitude value to assess the impact of
localized hot spots on the Bulk‐Power System, as suggested by the
Trade Associations.”
P49: “Consistent with Order No. 779, the Commission does not
specify a particular reference peak geoelectric field amplitude value
that should be applied to hot spots given present uncertainties.”
The directive is addressed in proposed TPL‐007‐2
through Requirements for applicable entities to perform
supplemental geomagnetic disturbance (GMD)
Vulnerability Assessments based on the supplemental
GMD event. The supplemental GMD event is a defined
event for assessing system performance that is not
based on spatially‐averaged data.
The supplemental GMD event is described in the
standard drafting team's (SDT) white paper available on
the project page:
http://www.nerc.com/pa/Stand/Pages/Project‐2013‐03‐
Geomagnetic‐Disturbance‐Mitigation.aspx
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
2
Consideration of Directives
# P
Directive/Guidance
Resolution
2) P65
REVISE R6 RE SPATIAL AVERAGING
P65: “Consistent with our determination above regarding the
reference peak geoelectric field amplitude value, the Commission
directs NERC to revise Requirement R6 to require registered entities
to apply spatially averaged and non‐spatially averaged peak
geoelectric field values, or some equally efficient and effective
alternative, when conducting thermal impact assessments.”
The directive is addressed in proposed TPL‐007‐2
Requirements R9 and R10. Applicable entities use
geomagnetically‐induced current (GIC) information for
the supplemental GMD event to perform supplemental
thermal impact assessments of applicable power
transformers.
Requirement R9 obligates responsible Planning
Coordinators and Transmission Planners to provide GIC
flow information to Transmission Owners and Generator
Owners for performing supplemental thermal impact
assessments. The GIC flow information is based on the
supplemental GMD event.
Requirement R10 obligates Transmission Owners and
Generator Owners to perform supplemental thermal
impact assessments on applicable power transformers
and provide results to responsible Planning Coordinators
and Transmission Planners.
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
3
Consideration of Directives
3) PP 88 REVISE STANDARD TO REQUIRE COLLECTION OF GMD DATA
90,
91, 92 P 88: “The Commission … adopts the NOPR proposal in relevant part
an directs NERC to develop revisions to Reliability Standard TPL‐007‐1
to require responsible entities to collect GIC monitoring and
magnetometer data as necessary to enable model validation and
situational awareness, including from any devices that must be added
to meet this need.
The NERC standard drafting team should address the criteria for
collecting GIC monitoring and magnetometer data discussed below
and provide registered entities with sufficient guidance in terms of
defining the data that must be collected, and NERC should propose in
the GMD research work plan how it will determine and report on the
degree to which industry is following that guidance.”
GIC Requirements
P 91: “Each responsible entity that is a transmission owner should be
required to collect necessary GIC monitoring data. However, a
transmission owner should be able to apply for an exemption from
the GIC monitoring data collection requirement if it demonstrates
that little or no value would be added to planning and operations.
In developing a requirement regarding the collection of GIC
monitoring data, NERC should consider the following criteria
discussed at the March 1, 2016 Technical Conference: (1) the GIC
data is from areas found to have high GIC based on system studies;
(2) the GIC data comes from sensitive installations and key parts of
the transmission grid; and (3) the data comes from GIC monitors that
are not situated near transportation systems using direct current
(e.g., subways or light rail.”
Magnetometer Requirements
P90: “In developing a requirement regarding the collection of
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
The directive is addressed in proposed TPL‐007‐2
Requirements R11 and R12.
Requirement R11 obligates responsible Planning
Coordinators and Transmission Planners to 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 SDT described GIC
data collection criteria in the guidance section to
promote consistency in achieving the reliability
objective and provide responsible entities with flexibility
to tailor procedures to their planning area. The guidance
addresses the following considerations: monitor
locations, monitor specifications, sampling interval,
collection periods, data format, and data retention.
Requirement R12 obligates responsible Planning
Coordinators and Transmission Planners to implement a
process to obtain geomagnetic field data for its Planning
Coordinator’s planning area. Sources of geomagnetic
field data include government observatories, installed
equipment owned or operated by the entity, and third‐
party sources. Entities are referred to INTRAMAGNET
guidance for criteria and considerations including data
sampling rate (10‐s or faster) and data format. By
requiring responsible Planning Coordinators and
Transmission Planners to obtain geomagnetic field data
for their planning areas, the requirement ensures data is
obtained from diverse geographic areas (latitudes and
longitudes) of the North American Bulk‐Power System.
4
Consideration of Directives
# P
Directive/Guidance
Resolution
magnetometer data, NERC should consider the following criteria
discussed at the March 1, 2016 Technical Conference: (1) the data is
sampled at a cadence of at least 10‐seconds or faster; (2) the data
comes from magnetometers that are physically close to GIC monitors;
(3) the data comes from magnetometers that are not near sources of
magnetic interference (e.g., roads and local distribution networks);
and (4) data is collected from magnetometers spread across wide
latitudes and longitudes and from diverse physiographic regions.”
***
P 91: GIC monitoring and magnetometer locations should also be
revisited after GIC system models are run with improved ground
conductivity models. NERC may also propose to incorporate the GIC
monitoring and magnetometer data collection requirements in a
different Reliability Standard (e.g., real‐time reliability monitoring and
analysis capabilities as part of the TOP Reliability Standards).
P 92: “[T]he Commission determines that requiring responsible
entities to collect necessary GIC monitoring and magnetometer data,
rather than install GIC monitors and magnetometers, affords greater
flexibility while obtaining significant benefits.”
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
5
Consideration of Directives
4) P 101, REVISE TPL‐007 TO REQUIRE DEADLINES FOR THE DEVELOPMENT
102
AND COMPLETION OF CORRECTIVE ACTION PLANS
P 101: “The Commission directs NERC to modify Reliability Standard
TPL‐007‐1 to include a deadline of one year from the completion of
the GMD Vulnerability Assessments to complete the development of
corrective action plans.”
P 102: “The Commission also directs NERC to modify Reliability
Standard TPL‐007‐1 to include a two‐year deadline after the
development of the corrective action plan to complete the
implementation of non‐hardware mitigation and four‐year deadline
to complete hardware mitigation…”
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
The directive is addressed in proposed TPL‐007‐2
Requirement R7.
Part 7.2 specifies that responsible entities must develop
Corrective Action Plans (CAP) within one year of
completing the benchmark GMD Vulnerability
Assessment.
Part 7.3 requires responsible entities to include a
timetable in the CAP that must specify:
Specify implementation of non‐hardware
mitigation, if any, within two years of
development of the CAP; and
Specify implementation of hardware mitigation,
if any, within four years of development of the
CAP.
Part 7.4 provides responsible entities with flexibility to
revise the CAP and timetables if situations beyond the
control of the responsible entity prevent
implementation of the CAP within the specified
timetable. The provision is necessary to account for
potential planning, siting, budgeting approval, or
regulatory uncertainties associated with transmission
system projects that are not within the responsible
entity’s control. Responsible entities are obligated to
document the revised CAP and update the revised CAP
every 12 calendar months until implemented.
Requirement R8 requires responsible entities to
complete a supplemental GMD Vulnerability
Assessment, based on the supplemental GMD event, to
evaluate localized enhancements of geomagnetic field
during a severe GMD event that could potentially affect
6
Consideration of Directives
the reliable operation of the Bulk‐Power System.
Localized enhancements of geomagnetic field can result
in geoelectric field values above the spatially‐averaged
benchmark in a local area. Part 8.3 specifies that if the
responsible entity concludes that there is Cascading
caused by the supplemental GMD event, then the
responsible entity shall conduct an analysis of possible
actions to reduce the likelihood or mitigate the impacts
and the event.
Proposed TPL‐007‐2 does not require responsible
entities to implement a Corrective Action Plan to
address impacts identified in the supplemental GMD
Vulnerability Assessment because mandatory mitigation
on the basis of the supplemental GMD Vulnerability
Assessment may not provide effective reliability benefit
or use industry resources optimally. As discussed in the
Supplemental GMD Event Description white paper, the
supplemental GMD event is based on a small number of
observed localized enhancement events that provide
only general insight into the geographic size of localized
events during severe solar storms. Additionally, the
state‐of‐the‐art modeling tools do not provide entities
with capabilities to realistically model localized
enhancements within a severe GMD event, and as a
result entities may need to employ conservative
approaches in the GMD Vulnerability Assessment such
as applying the localized peak geoelectric field over an
entire planning area.
The approach taken in TPL‐007‐2 to mitigating impacts
identified in the supplemental GMD Vulnerability
Assessment provides responsible entities with flexibility
to consider and select actions based on entity‐specific
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
7
Consideration of Directives
# P
Directive/Guidance
Resolution
factors. This is similar to the approach taken in
Reliability Standard TPL‐001‐4 for extreme events (TPL‐
001‐4 Requirement R3 Part 3.5).
Project 2013‐03 Geomagnetic Disturbance Mitigation | October 2017
8
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
TPL-007-2
Final Ballot Open through October 30, 2017
Now Available
A final ballot for TPL-007-2 - Transmission System Planned Performance for Geomagnetic Disturbance
Events is open through 8 p.m. Eastern, Monday, October 30, 2017.
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 associated with this project can log in and submit their vote here. If you
experience any difficulties using the Standards Balloting & Commenting System (SBS), contact Nasheema
Santos.
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, Scott Barfield-McGinnis via email
or at (404) 446-9689.
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 2013-03 Geomagnetic Disturbance Mitigation
Final Ballot | October 2017
2
Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Reliability Standard TPL-007-2
Applicable Standard
TPL‐007‐2 ‐ Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
TPL‐007‐1 ‐ 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 September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL‐007‐1 and its associated five‐year Implementation Plan. In the
Order, FERC also directed NERC to develop certain modifications to the standard. FERC established a
deadline of 18 months from the effective date of Order No. 830 for completing the revisions, which
is May 2018.
General Considerations
This Implementation Plan is intended to integrate the new requirements in TPL‐007‐2 with the GMD
Vulnerability Assessment process that is being implemented through approved TPL‐007‐1. At the
time of the May 2018 filing deadline, many requirements in approved standard TPL‐007‐1 that lead
to completion of the geomagnetic disturbance (GMD) Vulnerability Assessment will be in effect.
Furthermore, many entities may be taking steps to complete studies or assessments that are
required by future enforceable requirements in TPL‐007‐1. The Implementation Plan phases in the
requirements in TPL‐007‐2 based on the effective date of TPL‐007‐2, as follows:
Effective Date before January 1, 2021. Implementation timeline supports applicable entities
completing new requirements for supplemental GMD Vulnerability Assessments
concurrently with requirements for the benchmark GMD Vulnerability Assessment
(concurrent effective dates).
Effective Date on or after January 1, 2021. Implementation timeline supports applicable
entities completing the benchmark GMD Vulnerability Assessments before new
requirements for supplemental GMD Vulnerability Assessments become effective.
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.
Standard TPL‐007‐2
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 three (3) 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 three (3) 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
If TPL-007-2 becomes effective before January 1, 2021
Implementation timeline supports applicable entities completing new requirements for
supplemental GMD Vulnerability Assessments concurrently with requirements for the benchmark
GMD Vulnerability Assessment (concurrent effective dates).
Compliance Date for TPL‐007‐2 Requirements R1 and R2
Entities shall be required to comply with Requirements R1 and R2 upon the effective date of
Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
2
Compliance Date for TPL‐007‐2 Requirement R5
Entities shall not be required to comply with Requirements R5 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R11 and R12
Entities shall not be required to comply with Requirements R11 and R12 until 24 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until 30 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until 42 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R7
Entities shall not be required to comply with Requirement R7 until 54 months after the effective
date of Reliability Standard TPL‐007‐2.
If TPL-007-2 becomes effective on or after January 1, 2021
Implementation timeline supports applicable entities completing the benchmark GMD Vulnerability
Assessments before new requirements for supplemental GMD Vulnerability Assessments become
effective.
Compliance Date for TPL‐007‐2 Requirements R1, R2, R5, and R6
Entities shall be required to comply with Requirements R1, R2, R5, and R6 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3 and R4
Entities shall not be required to comply with Requirements R3 and R4 until 12 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R7, R11, and R12
Entities shall not be required to comply with Requirements R7, R11, and R12 until 24 months after
the effective date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
3
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until 36 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R10
Entities shall not be required to comply with Requirement R10 until 60 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R8
Entities shall not be required to comply with Requirement R8 until 72 months after the effective
date of Reliability Standard TPL‐007‐2.
Retirement Date
Standard TPL‐007‐1
Reliability Standard TPL‐007‐1 shall be retired immediately prior to the effective date of TPL‐007‐2 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 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
4
Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Reliability Standard TPL-007-2
Applicable Standard
TPL‐007‐2 ‐ Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
TPL‐007‐1 ‐ 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 September 22, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 830
approving Reliability Standard TPL‐007‐1 and its associated five‐year Implementation Plan. In the
Order, FERC also directed NERC to develop certain modifications to the standard. FERC established a
deadline of 18 months from the effective date of Order No. 830 for completing the revisions, which
is May 2018.
General Considerations
This Implementation Plan is intended to integrate the new requirements in TPL‐007‐2 with the GMD
Vulnerability Assessment process that is being implemented through approved TPL‐007‐1. At the
time of the May 2018 filing deadline, many requirements in approved standard TPL‐007‐1 that lead
to completion of the geomagnetic disturbance (GMD) Vulnerability Assessment will be in effect.
Furthermore, many entities may be taking steps to complete studies or assessments that are
required by future enforceable requirements in TPL‐007‐1. The Implementation Plan phases in the
requirements in TPL‐007‐2 based on the effective date of TPL‐007‐2, as follows:
Effective Date before January 1, 2021. Implementation timeline supports applicable entities
completing new requirements for supplemental GMD Vulnerability Assessments
concurrently with requirements for the benchmark GMD Vulnerability Assessment
(concurrent effective dates).
Effective Date on or after January 1, 2021. Implementation timeline supports applicable
entities completing the benchmark GMD Vulnerability Assessments before new
requirements for supplemental GMD Vulnerability Assessments become effective.
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.
Standard TPL‐007‐2
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 three (3) 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 three (3) 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
If TPL-007-2 becomes effective before January 1, 2021
Implementation timeline supports applicable entities completing new requirements for
supplemental GMD Vulnerability Assessments concurrently with requirements for the benchmark
GMD Vulnerability Assessment (concurrent effective dates).
Compliance Date for TPL‐007‐2 Requirements R1 and R2
Entities shall be required to comply with Requirements R1 and R2 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R5
Entities shall not be required to comply with Requirements R5 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
2
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until six (6) months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R11 and R12
Entities shall not be required to comply with Requirements R11 and R12 until 24 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until 30 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until 42 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R7
Entities shall not be required to comply with Requirement R7 until 54 months after the effective
date of Reliability Standard TPL‐007‐2.
If TPL-007-2 becomes effective on or after January 1, 2021
Implementation timeline supports applicable entities completing the benchmark GMD Vulnerability
Assessments before new requirements for supplemental GMD Vulnerability Assessments become
effective.
Compliance Date for TPL‐007‐2 Requirements R1, R2, R5, and R6
Entities shall be required to comply with Requirements R1, R2, R5, and R6 upon the effective date of
Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R3 and R4
Entities shall not be required to comply with Requirements R3 and R4 until 12 months after the
effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirements R7, R11, and R12
Entities shall not be required to comply with Requirements R7, R11, and R12 until 24 months after
the effective date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R9
Entities shall not be required to comply with Requirement R9 until 36 months after the effective
date of Reliability Standard TPL‐007‐2.
Implementation Plan
Project 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
3
Compliance Date for TPL‐007‐2 Requirement R10
Entities shall not be required to comply with Requirement R10 until 60 months after the effective
date of Reliability Standard TPL‐007‐2.
Compliance Date for TPL‐007‐2 Requirement R8
Entities shall not be required to comply with Requirement R8 until 72 months after the effective
date of Reliability Standard TPL‐007‐2.
Retirement Date
Standard TPL‐007‐1
Reliability Standard TPL‐007‐1 shall be retired immediately prior to the effective date of TPL‐007‐2 in
the particular jurisdiction in which the revised standard is becoming effective, provided that the TPL‐
007‐1 Implementation Plan shall remain in effect to the extent necessary until the phased‐in
compliance dates above are implemented for TPL‐007‐2.
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 2013‐03 Geomagnetic Disturbance Mitigation | January 2018
4
| File Type | application/pdf |
| Author | Courtney Baughan |
| File Modified | 2018-05-10 |
| File Created | 2018-01-22 |