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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
EOP-010-1 – GEOMAGNETIC DISTURBANCE OPERATIONS
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
Stacey Tyrewala
Senior Counsel
Brady Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
November 14, 2013
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TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II. NOTICES AND COMMUNICATIONS ................................................................................ 4
III. BACKGROUND .................................................................................................................... 4
A.
Regulatory Framework ..................................................................................................... 4
B.
NERC Reliability Standards Development Process ......................................................... 5
C.
Technical Background: Geomagnetic Disturbances ....................................................... 6
D.
History of Project 2013-03, Geomagnetic Disturbance Mitigation ................................. 7
IV. JUSTIFICATION FOR APPROVAL .................................................................................... 8
A.
Applicability of EOP-010-1 – Geomagnetic Disturbance Operations ............................. 8
B.
Requirements in EOP-010-1 – Geomagnetic Disturbance Operations .......................... 10
C.
Commission Directives Addressed ................................................................................ 15
D.
Enforceability of EOP-010-1 ......................................................................................... 16
V. CONCLUSION ..................................................................................................................... 17
Exhibit A
Proposed Reliability Standard, EOP-010-1 –Geomagnetic Disturbance Operations
Exhibit B
Implementation Plan for EOP-010-1
Exhibit C
Order No. 672 Criteria for EOP-010-1
Exhibit D
White Paper Supporting Network Applicability of EOP-010-1
Exhibit E
White Paper Supporting Functional Entity Applicability of EOP-010-1
Exhibit F
Analysis of Violation Risk Factors and Violation Security Levels
Exhibit G
Analysis of Commission Directives
Exhibit H
Summary of Development History and Complete Record of Development
Exhibit I
Standard Drafting Team Roster for Project 2013-03, Geomagnetic Disturbance
Mitigation
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
EOP-010-1 – GEOMAGNETIC DISTURBANCE OPERATIONS
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”)1 and Section 39.52 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”)3 hereby submits proposed Reliability
Standard EOP-010-1 for Commission approval. NERC requests that the Commission approve
proposed Reliability Standard EOP-010-1 (Exhibit A) and find that the proposed Reliability
Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.4
NERC also requests approval of the associated implementation plan (Exhibit B), Violation Risk
Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibit F), as detailed in this
petition.
As required by Section 39.5(a)5 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standard EOP-010-1, a demonstration
that the proposed Reliability Standard meets the criteria identified by the Commission in Order
1
16 U.S.C. § 824o (2006).
18 C.F.R. § 39.5 (2013).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO
Certification Order”).
4
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available at http://www.nerc.com/files/Glossary_of_Terms.pdf.
5
18 C.F.R. § 39.5(a) (2013).
2
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No. 6726 (Exhibit C) and a summary of the development history (Exhibit H). Proposed
Reliability Standard EOP-010-1 was approved by the NERC Board of Trustees on November 7,
2013.
I.
EXECUTIVE SUMMARY
Geomagnetic disturbances (“GMD”) occur when solar storms on the sun’s surface send
electrically charged particles toward earth, where they interact with the earth’s magnetic
field. Proposed Reliability Standard EOP-010-1—Geomagnetic Disturbance Operations would
be a new Reliability Standard that attempts to mitigate the effects of GMD events by
implementing Operating Plans,7 Operating Processes,8 and Operating Procedures9 and is
responsive to Commission concerns in Order No. 779.10
In Order No. 779, the Commission directed the development of Reliability Standards to
address GMDs in two stages.11 In the first stage, the subject of this petition, NERC is submitting
proposed Reliability Standard EOP-010-1, requiring owners and operators of the Bulk-Power
System to develop and implement Operational Procedures to mitigate the effects of GMDs
6
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
7
An “Operating Plan” is defined in the Glossary of Terms Used in NERC Reliability Standards as “A
document that identifies a group of activities that may be used to achieve some goal. An Operating Plan may contain
Operating Procedures and Operating Processes. A company-specific system restoration plan that includes an
Operating Procedure for black-starting units, Operating Processes for communicating restoration progress with other
entities, etc., is an example of an Operating Plan.” Available at http://www.nerc.com/files/Glossary_of_Terms.pdf
8
The term “Operating Procedure” is defined in the Glossary of Terms Used in NERC Reliability Standards
as “A document that identifies specific steps or tasks that should be taken by one or more specific operating
positions to achieve specific operating goal(s). The steps in an Operating Procedure should be followed in the order
in which they are presented, and should be performed by the position(s) identified. A document that lists the specific
steps for a system operator to take in removing a specific transmission line from service is an example of an
Operating Procedure.” Available at http://www.nerc.com/files/Glossary_of_Terms.pdf
9
The term “Operating Process” is defined in the Glossary of Terms Used in NERC Reliability Standards as
“A document that identifies general steps for achieving a generic operating goal. An Operating Process includes
steps with options that may be selected depending upon Real-time conditions. A guideline for controlling high
voltage is an example of an Operating Process.” Available at http://www.nerc.com/files/Glossary_of_Terms.pdf
10
Reliability Standards for Geomagnetic Disturbances, Order No. 779, 143 FERC ¶ 61,147 (2013)(“Order
No. 779”).
11
Id.
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consistent with the reliable operation of the Bulk-Power System. The second stage of Reliability
Standards to address GMDs, currently under development, requires NERC to develop proposed
Reliability Standards that require owners and operators of the Bulk-Power System to conduct
initial and on-going vulnerability assessments of the potential impact of benchmark GMD events
on Bulk-Power System equipment and the Bulk-Power System as a whole.12
During a severe GMD event, geomagnetically-induced current (“GIC”) flow in
transformers (resulting in half-cycle saturation) can substantially increase absorption of reactive
power, create harmonics, and, in some cases, cause transformer hot-spot heating, which could
lead to loss of Reactive Power support-- thereby causing voltage instability, protective relay
Misoperations and potential equipment loss-of-life or damage. As a high-impact, low-frequency
event, GMDs pose a unique threat to Bulk-Power System reliability, and the proposed Reliability
Standard is intended to lessen the impact of such events.
As the Commission noted in Order No. 779, “[o]perational procedures may help alleviate
abnormal system conditions due to transformer absorption of reactive power during GMD
events, helping to stabilize system voltage swings, and may potentially isolate some equipment
from being damaged or misoperated.”13 The proposed Reliability Standard allows entities to
tailor their Operating Plans, Processes and Procedures based on the responsible entity’s
assessment of entity-specific factors, such as geography, geology, and system topology. The
coordination of the Operating Plans, Processes and Procedures would be overseen by the
Reliability Coordinator, consistent with its wide-area perspective.
The proposed Reliability Standard is an important first step in addressing the issue of
GMDs and can be implemented relatively quickly. While responsible entities will develop and
12
See Order No. 779 at P 54. The Second Stage GMD Reliability Standard must identify what severity GMD
events (i.e., benchmark GMD events) that responsible entities will have to assess for potential impacts on the BulkPower System.
13
Id. at P 36.
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implement Operational Procedures or Operational Processes, NERC will continue to support
those efforts through the GMD Task Force, for example, by identifying and sharing Operating
Plans, Processes, and Procedures found to be the most effective.
NERC requests that the Commission approve proposed Reliability Standard EOP-010-1
and find that the proposed Reliability Standard is just, reasonable, not unduly discriminatory or
preferential, and in the public interest.
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:14
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
Stacey Tyrewala*
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
III.
Mark G. Lauby*
Vice President and Director of Standards
Laura Hussey*
Director of Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
[email protected]
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005,15 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
14
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2013), to allow the inclusion
of more than two persons on the service list in this proceeding.
15
16 U.S.C. § 824o (2006).
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enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1)16
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
States will be subject to Commission-approved Reliability Standards. Section 215(d)(5)17 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a)18 of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should be made effective.
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA19 and Section 39.5(c)20 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
B.
NERC Reliability Standards Development Process
The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.21 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
16
Id. § 824(b)(1).
Id. § 824o(d)(5).
18
18 C.F.R. § 39.5(a) (2012).
19
16 U.S.C. § 824o(d)(2).
20
18 C.F.R. § 39.5(c)(1).
21
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
17
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Development) of its Rules of Procedure and the NERC Standard Processes Manual.22 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable
notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfies certain of the criteria for approving Reliability
Standards.23 The development process is open to any person or entity with a legitimate interest
in the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders,
and a vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard before the Reliability Standard is submitted to the Commission for approval.
C.
Technical Background: Geomagnetic Disturbances
A GMD is caused by solar events resulting in distortions of the earth’s magnetic field,
and can be of varying intensity. The science regarding the impacts of GMDs on electric power
systems is still in the developmental stages and much remains to be learned about the unique
threat GMDs pose to reliability. The characteristics of GMDs (e.g., the peak and duration of
induced geo-electric fields) experienced by the power system is dependent on a number of
factors, including where the geomagnetic storm is centered, the direction of the fields along with
their polarity, geomagnetic latitude, and the geology (electrical conductivity of the ground). As
the Commission noted in Order No. 779, “while there is an ongoing debate as to how a severe
GMD event will most likely impact the Bulk-Power System, there is a general consensus that
GMD events can cause wide-spread blackouts due to voltage instability and subsequent voltage
collapse, thus disrupting the reliable operation of the Bulk-Power System.”24
22
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
23
116 FERC ¶ 61,062 at P 250 (2006).
24
Order No. 779 at P 24 (internal citation omitted).
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D.
History of Project 2013-03, Geomagnetic Disturbance Mitigation
In June 2010, NERC identified that GMDs were a serious threat to the reliable operation
of the Bulk-Power System and that this issue required significant staff and industry attention
with close monitoring of progress. Since that time, NERC has spent a substantial amount of time
and effort working with experts across the North American power industry, U.S. and Canadian
government agencies, transformer manufacturers, and other vendors, in developing scientifically
sound and repeatable conclusions.
In early 2011, a NERC-sponsored GMD Task Force was formed to “develop a technical
white paper describing the evaluation of scenarios of potential GMD impacts, identifying key
bulk power system parameters under those scenario conditions, and evaluating potential
reliability implications of these incidents.”25 The resulting report, the NERC Interim GMD
Report evaluating the effects of GMDs on the Bulk-Power System, was issued in February
2012.26
In October 2012, the Commission issued a Notice of Proposed Rulemaking (“NOPR”)
proposing to direct that NERC submit to the Commission for approval proposed Reliability
Standards that address the risks posed by GMDs to the reliable operation of the Bulk-Power
System.27 The NOPR stated that GMD vulnerabilities are not adequately addressed in the
existing Reliability Standards and that this constitutes a reliability gap because GMD events can
cause the Bulk-Power System to collapse suddenly and can potentially damage equipment on the
25
NERC, Board of Trustees Minutes, Exhibit J, at 1 (Nov. 4, 2010), available at
http://www.nerc.com/docs/docs/bot/BOT-1110m-open-complete.pdf.
26
North American Electric Reliability Corp., 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System (February 2012) (“NERC Interim
GMD Report”), available at http://www.nerc.com/files/2012GMD.pdf.
27
Reliability Standards for Geomagnetic Disturbances, Notice of Proposed Rulemaking, 77 FR 64,935 (Oct.
24, 2012), 141 FERC ¶ 61,045 (2012) (“NOPR”).
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Bulk-Power System.28 In May 2013, the Commission issued Order No. 779 directing NERC to
develop proposed Reliability Standards addressing GMD events in two stages, as explained
herein.
IV.
JUSTIFICATION FOR APPROVAL
As discussed in detail in Exhibit C, proposed Reliability Standard EOP-010-1--
Geomagnetic Disturbance Operations satisfies the Commission’s criteria in Order No. 672 and is
just, reasonable, not unduly discriminatory or preferential, and in the public interest. The
purpose of proposed Reliability Standard EOP-010-1 is to mitigate the reliability impacts of
GMD events by implementing Operating Plans, Processes, and Procedures. Provided below is
an explanation of the applicability of the proposed Reliability Standard and a justification on a
Requirement-by-Requirement basis.
A.
Applicability of EOP-010-1 – Geomagnetic Disturbance Operations
The proposed Reliability Standard is applicable to: (1) Transmission Operators with a
Transmission Operator Area that includes a power transformer with a high side wye-grounded
winding with terminal voltage greater than 200 kV, and (2) Reliability Coordinators.29 This
applicability is consistent with Order No. 779 and the NERC Functional Model.
As the Commission noted in Order No. 779, “[b]ecause many Bulk-Power System
transformers are grounded, the GIC appears as electrical current to the Bulk-Power System and
flows through the ground connection and conductors, such as transformers and transmission
lines.”30 The applicability of proposed Reliability Standard EOP-010-1 recognizes the technical
considerations of the impact of a GMD on the Bulk-Power System.
28
Id. at P 4.
A power transformer with a “high side wye-grounded winding” refers to a power transformer with
windings on the high voltage side that are connected in a wye configuration and have a grounded neutral connection.
30
Order No. 779 at P 6 citing North American Electric Reliability Corp., 2012 Special Reliability Assessment
29
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The NERC Functional Model is structured to ensure that there are no gaps or overlaps in
the performance of operation Tasks in the operating timeframe anywhere in the Bulk Electric
System.31 A Reliability Coordinator has responsibility and authority for reliable operation within
the Reliability Coordinator Area. A Reliability Coordinator’s scope includes a wide-area view
with situational awareness of neighboring Reliability Coordinator Areas. Its scope includes both
transmission and balancing operations, and it has the authority to direct other functional entities
to take certain actions to ensure that its Reliability Coordinator Area operates reliably.
Like the Reliability Coordinator, the Transmission Operator has responsibility and
authority for the reliable operation of the transmission system within a specified area. The
Transmission Operator is responsible for the Real-time operating reliability of the transmission
assets under its purview, which is referred to as the Transmission Operator Area. The
Transmission Operator has the authority to take certain actions to ensure that its Transmission
Operator Area operates reliably.
Together, the inclusion of these two functional entities— Reliability Coordinators and
Transmission Operators— in proposed Reliability Standard EOP-010-1, provides for the
development and implementation of Operational Procedures and coordination across regions.32
Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System at ii (February 2012) (NERC
Interim GMD Report), available at http://www.nerc.com/files/2012GMD.pdf.
31
The NERC Reliability Functional Model is available at:
http://www.nerc.com/pa/Stand/Functional%20Model%20Archive%201/Functional_Model_V5_Final_2009Dec1.pdf
32
The NERC Functional Model describes the relationships between functional entities in performing their
reliability related tasks. The Reliability Coordinator "Coordinates with Transmission Operators on system
restoration plans, contingency plans, and reliability-related services" ahead of time, and " Issues corrective actions
and emergency procedures directives to Transmission Operators, Balancing Authorities, Generator Operators,
Distribution Providers, and Interchange Coordinators" in real time.
Available at:
http://www.nerc.com/pa/Stand/Functional%20Model%20Archive%201/Functional_Model_V5_Final_2009Dec1.pdf
See also, Exhibit E.
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As explained in Exhibit D, the applicability threshold of greater than 200 kV is based on
analysis by the standard drafting team. There are several key parameters in assessing the impacts
of a GMD, including:
Transformer grounding and core construction;
System topology;
Geographic location;
Resistance values of the elements of the DC network used to evaluate GIC
distribution within the network.
Based on an analysis of these factors, the standard drafting team determined that a voltage
threshold of greater than 200 kV is appropriate. This finding is supported by operating
experience and the preponderance of peer-reviewed studies on GMD effects.33 Further, the
standard drafting team determined that the effect of GIC in networks less than 200 kV has
negligible impact on the reliability of the interconnected transmission system. Therefore, as
noted above, the applicability of proposed Reliability Standard EOP-010-1 also recognizes the
technical considerations of the impact of a GMD on the Bulk-Power System.
B.
Requirements in EOP-010-1 – Geomagnetic Disturbance Operations
The proposed Reliability Standard consists of three Requirements. Requirement R1
addresses coordination within a Reliability Coordinator Area. Requirement R2 addresses the
dissemination of space weather information to ensure that entities within a Reliability
Coordinator Area have the appropriate information necessary to take action and that the same
information is available to all entities. Requirement R3 requires the development of GMD
Operating Procedures or Processes. Collectively, these Requirements satisfy the Commission’s
33
See Exhibit D.
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directives in Order No. 779 and are intended to mitigate the effects of GMD events through the
implementation of Operating Plans, Processes, and Procedures.
Proposed Requirements
R1.
Each Reliability Coordinator shall develop, maintain, and implement a GMD Operating
Plan that coordinates GMD Operating Procedures or Operating Processes within its
Reliability Coordinator Area. At a minimum, the GMD Operating Plan shall include:
1.1
A description of activities designed to mitigate the effects of GMD events on the
reliable operation of the interconnected transmission system within the Reliability
Coordinator Area.
1.2
A process for the Reliability Coordinator to review the GMD Operating
Procedures or Operating Processes of Transmission Operators within its
Reliability Coordinator Area.
Requirement R1 of proposed Reliability Standard EOP-010-1 requires several actions
from Reliability Coordinators: development, maintenance, and implementation of a GMD
Operating Plan, as well as coordination. An Operating Plan is maintained when it is kept
relevant by taking into consideration system configuration, conditions, or operating experience,
as needed to accomplish its purpose. An Operating Plan is implemented by carrying out its
stated actions. The coordination is intended to ensure that Operating Procedures and Operating
Processes within a Reliability Coordinator Area34 are not in conflict with one another; it is not
intended to be a review by the Reliability Coordinator of the technical aspects of the GMD
Operating Procedures or Processes. Transmission Operators are responsible for the technical
integrity of their Operating Procedures or Processes pursuant to Requirement R3. For example,
if Company A submitted an Operating Procedure proposing to take Line X out of service under
specified GMD conditions, and Company B submitted an Operating Procedure that relies on
Line X remaining in service in the event of a GMD -- it is the responsibility of the Reliability
34
The term “Reliability Coordinator Area” is defined in the Glossary of Terms Used in NERC Reliability
Standards as “The collection of generation, transmission, and loads within the boundaries of the Reliability
Coordinator. Its boundary coincides with one or more Balancing Authority Areas.”
Available at http://www.nerc.com/files/Glossary_of_Terms.pdf
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Coordinator to identify this conflict. The Reliability Coordinator could then require Company A
and Company B to resolve this conflict and resubmit their Operating Procedures.
Part 1.1 of Requirement R1 requires Reliability Coordinators to describe the activities
that must be undertaken in order to mitigate the effects of a GMD. Those activities could require
a Balancing Authority to take action. Pursuant to IRO-001, the Reliability Coordinator has clear
decision-making authority to act and to direct actions to be taken by Transmission Operators,
Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving
Entities, and Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the
integrity and reliability of the Bulk Electric System. Part 1.2 of Requirement R1 requires
Reliability Coordinators to establish a process to review the GMD Operating Procedures or
Operating Processes of the Transmission Operators in the Reliability Coordinator Area
R2.
Each Reliability Coordinator shall disseminate forecasted and current space weather
information to functional entities identified as recipients in the Reliability Coordinator's
GMD Operating Plan.
Requirement R2 of proposed Reliability Standard EOP-010-1 addresses the
dissemination of space weather information; such information can be used for situational
awareness and safe posturing of the system. Space weather information can also be used for
monitoring the progress of a GMD event. As the entity with a wide-area view, the Reliability
Coordinator is responsible for disseminating space weather information to ensure coordination
and consistent awareness in its Reliability Coordinator Area.
Requirement R2 of proposed Reliability Standard EOP-010-1 replaces IRO-005-3.1a,
Requirement R3. IRO-005- 3.1a, Requirement R3 states:
Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
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Reliability Standard IRO-005-4, which addresses reliability coordination for current day
operations, has been adopted by the NERC Board and filed with the Commission, and would
retire IRO-005-3.1a , Requirement R3.35 Therefore, to ensure responsibility for disseminating
space weather information in the Reliability Coordinator Area is maintained while avoiding
duplicative requirements being enforceable at the same time, if proposed Reliability Standard
EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 of EOP010-1 shall become effective on the first day following retirement of IRO-005-3.1a as detailed in
Exhibit B.
R3.
Each Transmission Operator shall develop, maintain, and implement a GMD Operating
Procedure or Operating Process to mitigate the effects of GMD events on the reliable
operation of its respective system. At a minimum, the Operating Procedure or Process
shall include:
3.1.
3.2.
3.3.
Steps or tasks to receive space weather information.
System Operator actions to be initiated based on predetermined conditions.
The conditions for terminating the Operating Procedure or Operating Process.
Requirement R3 of proposed Reliability Standard EOP-010-1 requires Transmission
Operators to develop Operating Procedures or Operating Processes to address GMD events.
Similar to Requirement R1, an Operating Procedure or Operating Process is implemented by
carrying out its stated actions. An Operating Procedure or Operating Process is maintained when
it is kept relevant by taking into consideration system configuration, conditions, or operating
experience, as needed to accomplish its purpose. Requirement R3 is not prescriptive and allows
35
Reliability Standard IRO-005-4 provides:
Requirement R1. When the results of an Operational Planning Analysis or Real-time Assessment indicate
an anticipated or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each
Reliability Coordinator shall notify all impacted Transmission Operators and Balancing Authorities in its Reliability
Coordinator Area.
Requirement R2. Each Reliability Coordinator that identifies an anticipated or actual condition with
Adverse Reliability Impacts within its Reliability Coordinator Area shall notify all impacted Transmission Operators
and Balancing Authorities in its Reliability Coordinator Area when the problem has been mitigated.
13
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entities to tailor their Operational Procedures or Processes based on the responsible entity’s
assessment of entity-specific factors, such as geography, geology, and system topology. This
approach is consistent with the development of results-based Reliability Standards.36 As the
Commission noted in Order No. 779, owners and operators of the Bulk-Power System are most
familiar with their own equipment and system configurations.37
Part 3.1 of Requirement R3 requires Transmission Operators to specify in their Operating
Procedures or Processes steps or tasks that must be conducted to receive space weather
information. Part 3.2 of Requirement R3 requires Transmission Operators to specify what
actions must be taken under what conditions and such conditions must be predetermined. Part
3.3 of Requirement R3 requires Transmission Operators to specify when and under what
conditions the Operating Procedure or Process is exited. For example, if an Operating Procedure
specifies that certain actions must be taken when a space weather alert is received, the Operating
Procedure should specify when such actions would be terminated. Collectively, these Parts of
Requirement R3 ensure that there is a baseline level of detail in the Operating Procedures or
Processes while maintaining necessary flexibility in order to allow responsible entities to tailor
their Operating Procedures or Processes as needed. Furthermore, the proposed Reliability
Standard is technology neutral.
Proposed Reliability Standard EOP-010-1 does not prescribe specific actions that must be
taken by responsible entities because a “one-size fits all” approach to crafting GMD Reliability
Standards would fail to recognize the important role of locational differences.38 Indeed, the
36
Results-based Reliability Standards focus on required actions or results and not necessarily the methods by
which those actions or results must be accomplished.
37
Order No. 779 at P 38.
38
As Commissioner LaFleur has noted, the panelists at the April 30, 2012 FERC technical conference agreed
that “there can be considerable differences in GMD exposure and impacts depending on geography, where you are
in the earth, ground conditions, grid configuration, and equipment condition…” See Electric Infrastructure Security
Summit III, London, May 14-15, 2012, The House of Parliament, United Kingdom at p. 25.
14
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Commission stated in Order No. 779 that it “do[es] not expect that owners and operators of the
Bulk-Power System will necessarily develop and implement the same operational procedures.”39
The standard drafting team determined that the variability in the impacts of GMD precludes the
development of prescriptive requirements.40
For these reasons, the proposed Reliability Standard is just and reasonable and should
mitigate the effects of GMD events through the implementation of Operating Plans, Processes,
and Procedures.
C.
Commission Directives Addressed
As explained in Exhibit G, the proposed Reliability Standard satisfies all of the
Commission’s directives in Order No. 779 with respect to Stage 1 of the GMD Reliability
Standards. Requirements R1 and R3 of proposed Reliability Standard EOP-010-1 satisfy the
Commission’s directive to submit “within six months of the effective date of this Final Rule, one
or more Reliability Standards requiring owners and operators of the Bulk-Power System to
develop and implement operational procedures to mitigate the effects of GMDs consistent with
the reliable operation of the Bulk-Power System.”41 Requirement R1 requires Reliability
Coordinators to develop, maintain and implement a GMD Operating Plan that coordinates GMD
Operating Procedures within its Reliability Coordinator Area. Requirement R3 requires
Transmission Operators to develop, maintain, and implement an Operating Procedure or
Operating Process to mitigate the effects of GMD events on the reliable operation of its
respective system. Order No. 779 became effective on July 22, 2013 and the instant petition is
being submitted within six months, in compliance with the Commission’s directive. The
39
40
41
Order No. 779 at P 38 (emphasis added).
See Consideration of Comments: Project 2013-03 (August 30, 2013) at p. 37.
Order No. 779 at P 30.
15
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proposed Reliability Standard satisfies the Commission’s directives and also addresses the
Commission’s concerns regarding the need for flexibility in Operational Procedures.
D.
Enforceability of EOP-010-1
The proposed Reliability Standard includes Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”). The VSLs provide guidance on the way that NERC will
enforce the Requirements of the proposed Reliability Standard. The VRFs are one of several
elements used to determine an appropriate sanction when the associated Requirement is violated.
The VRFs assess the impact to reliability of violating a specific Requirement. The VRFs and
VSLs for the proposed Reliability Standards comport with NERC and Commission guidelines
related to their assignment. For a detailed review of the VRFs, the VSLs, and the analysis of
how the VRFs and VSLs were determined using these guidelines, please see Exhibit F.
The proposed Reliability Standard also include Measures that support each Requirement
by clearly identifying what is required and how the Requirement will be enforced. These
Measures help ensure that the Requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party.42
42
Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.”).
16
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V.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:
•
approve the proposed Reliability Standard and associated elements included in Exhibit
A, effective as proposed herein;
•
approve the implementation plan included in Exhibit B as proposed herein.
Respectfully submitted,
/s/ Stacey Tyrewala
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
Stacey Tyrewala
Senior Counsel
Brady Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: November 14, 2013
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Exhibit A
Proposed Reliability Standard
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EOP-010-1 — Geomagnetic Disturbance Operations
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Plans, Processes, and Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes a
power transformer with a high side wye-grounded winding with terminal
voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to adversely impact the
reliable operation of interconnected transmission systems. 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
Protection System Misoperation, the combination of which may result in voltage
collapse and blackout.
6.
Effective Date:
The first day of the first calendar quarter that is six months after the date that this
standard is approved by an applicable governmental authority or as otherwise provided
for in a jurisdiction where approval by an applicable governmental authority is required
for a standard to go into effect. Where approval by an applicable governmental
authority is not required, the standard shall become effective on the first day of the first
calendar quarter that is six months after the date this standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements and Measures
R1. Each Reliability Coordinator shall develop, maintain, and implement a GMD Operating
Plan that coordinates GMD Operating Procedures or Operating Processes within its
Reliability Coordinator Area. At a minimum, the GMD Operating Plan shall include:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations
Planning, Same-day Operations, Real-time Operations]
1.1 A description of activities designed to mitigate the effects of GMD events on the
reliable operation of the interconnected transmission system within the
Reliability Coordinator Area.
1.2 A process for the Reliability Coordinator to review the GMD Operating
Procedures or Operating Processes of Transmission Operators within its
Reliability Coordinator Area.
Page 1 of 7
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EOP-010-1 — Geomagnetic Disturbance Operations
M1. Each Reliability Coordinator shall have a current GMD Operating Plan meeting all the
provisions of Requirement R1; evidence such as a review or revision history to indicate
that the GMD Operating Plan has been maintained; and evidence to show that the plan
was implemented as called for in its GMD Operating Plan, such as dated operator logs,
voice recordings, or voice transcripts.
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information to functional entities identified as recipients in the Reliability
Coordinator's GMD Operating Plan. [Violation Risk Factor: Medium] [Time Horizon:
Same-day Operations, Real-time Operations]
M2. Each Reliability Coordinator shall have evidence such as dated operator logs, voice
recordings, transcripts, or electronic communications to indicate that forecasted and
current space weather information was disseminated as stated in its GMD Operating
Plan.
R3. Each Transmission Operator shall develop, maintain, and implement a GMD
Operating Procedure or Operating Process to mitigate the effects of GMD events on
the reliable operation of its respective system. At a minimum, the Operating Procedure
or Operating Process shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning, Operations Planning, Same-day Operations, Real-Time
Operations]
3.1. Steps or tasks to receive space weather information.
3.2. System Operator actions to be initiated based on predetermined conditions.
3.3. The conditions for terminating the Operating Procedure or Operating Process.
M3. Each Transmission Operator shall have a GMD Operating Procedure or Operating
Process meeting all the provisions of Requirement R3; evidence such as a review or
revision history to indicate that the GMD Operating Procedure or Operating Process
has been maintained; and evidence to show that the Operating Procedure or Operating
Process was implemented as called for in its GMD Operating Procedure or Operating
Process, such as dated operator logs, voice recordings, or voice transcripts.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) 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
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EOP-010-1 — Geomagnetic Disturbance Operations
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 Reliability Coordinator and Transmission Operator shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity 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 CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Page 3 of 7
EOP-010-1 — Geomagnetic Disturbance Operations
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning,
Operations
Planning,
Same-day
Operations,
Real-time
Operations
Medium The Reliability
Coordinator had a
GMD Operating Plan,
but failed to maintain
it.
R2
Same-day
Operations,
Real-time
Operations
Medium N/A
R3
Long-term
Planning,
Operations
Planning,
Medium The Transmission
Operator had a GMD
Operating Procedure
or Operating Process,
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan failed
to include one of the
required elements as
listed in Requirement
R1, parts 1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
N/A
N/A
The Reliability
Coordinator failed to
disseminate forecasted
and current space
weather information to
all functional entities
identified as recipients
in the Reliability
Coordinator's GMD
Operating Plan.
The Transmission
Operator's GMD
Operating Procedure
or Operating Process
The Transmission
Operator's GMD
Operating Procedure or
Operating Process
The Transmission
Operator did not have
a GMD Operating
Procedure or Operating
OR
The Reliability
Coordinator failed to
implement a GMD
Operating Plan within
its Reliability
Coordinator Area.
Page 4 of 7
EOP-010-1 — Geomagnetic Disturbance Operations
Same-day
Operations,
Real-time
Operations
but failed to maintain
it.
failed to include one of
the required elements
as listed in
Requirement R3, parts
3.1 through 3.3.
failed to include two or
more of the required
elements as listed in
Requirement R3, parts
3.1 through 3.3.
Process
OR
The Transmission
Operator failed to
implement its GMD
Operating Procedure or
Operating Process.
Page 5 of 7
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EOP-010-1 — Geomagnetic Disturbance Operations
D. Regional Variances
None.
E. Interpretations
None.
F. Guideline and Technical Basis
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for R1:
An Operating Plan is implemented by carrying out its stated actions.
Coordination is intended to ensure that Operating Procedures are not in conflict with one
another. An Operating Plan is maintained when it is kept relevant by taking into consideration
system configuration, conditions, or operating experience, as needed to accomplish its purpose.
Elements of Requirement R1 take place in various time horizons. Development of the GMD
Operating Plan occurs in the Long-Term Planning Time Horizon. Maintenance of the GMD
Operating Plan occurs in the Operations Planning Time Horizon. Implementation of the GMD
Operating Plan occurs in the Operations Planning, Same-Day and Real-Time Time Horizons.
Rationale for R2:
Requirement R2 replaces IRO-005-3.1a, Requirement R3. IRO-005-4 has been adopted by the
NERC Board and filed with FERC, and will retire IRO-005-3.1a Requirement R3. If EOP-010-1
becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall become
effective on the first day following retirement of IRO-005-3.1a.
Space weather forecast information can be used for situational awareness and safe posturing of
the system. Current space weather information can be used for monitoring progress of a GMD
event.
The Reliability Coordinator is responsible for disseminating space weather information to ensure
coordination and consistent awareness in its Reliability Coordinator Area.
Rationale for R3:
In developing an Operating Procedure or Operating Process, an entity may consider entityspecific factors such as geography, geology, and system topology.
An Operating Procedure or Operating Process is maintained when it is kept relevant by taking
into consideration system configuration, conditions, or operating experience, as needed to
accomplish its purpose.
Page 6 of 7
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EOP-010-1 — Geomagnetic Disturbance Operations
Version History
Version
1
Date
Action
11/07/2013
Adopted by the NERC Board of
Trustees
Change Tracking
Page 7 of 7
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Exhibit B
Implementation Plan
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
R etirem ents
None
R evisions to Glossary Term s
None
Applicable Entities
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side wye-grounded winding with terminal voltage greater than 200 kV
Conform ing Changes to Other Standards
None
Effective Dates
Requirement R2 of EOP-010-1 replaces Requirement R3 of IRO-005-3.1a. IRO-005-4 has been adopted
by the NERC Board and filed with FERC in Docket Number RM13-15-000, and will retire Requirement
R3 of IRO-005-3.1a:
IRO-005-3.1a, Requirement R3:
R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
EOP-010-1 replaces this requirement with the following:
EOP-010-1, Requirement R2:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information to functional entities identified as recipients in the Reliability Coordinator's
GMD Operating Plan.
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Therefore, to ensure responsibility for disseminating space weather information in the Reliability
Coordinator Area is maintained while avoiding duplicative requirements being enforceable at the same
time, EOP-010-1 shall become effective as follows:
In jurisdictions where regulatory approval is required:
•
The first day of the first calendar quarter that is six months after the date that this standard is
approved by an applicable governmental authority or as otherwise provided for in that
jurisdiction.
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
In jurisdictions where regulatory approval is not required:
•
The first day of the first calendar quarter that is six months after the date this standard is
adopted by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan
2
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Exhibit C
Order No. 672 Criteria
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Exhibit C -- Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672,1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria.
1.
Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
Proposed Reliability Standard EOP-010-1 achieves the specific reliability goal of
mitigating the effects of geomagnetic disturbance (“GMD”) events on the Bulk-Power System.
Such events pose a unique threat to reliability and the proposed Reliability Standard will lessen
their impact by requiring the development of Operating Plans, Operating Procedures, and
Operating Processes for use in anticipation of, and during, GMD events. Operating Plans,
Procedures, and Processes will be developed with the goal of stabilizing system voltage swings
and isolating equipment that may be vulnerable to damage or Misoperation during the course of
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls within the
requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power System
facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such facilities
include all those necessary for operating an interconnected electric energy transmission network, or any portion of
that network, including control systems. The proposed Reliability Standard may apply to any design of planned
additions or modifications of such facilities that is necessary to provide for reliable operation. It may also apply to
Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose
a topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard
should be developed initially by persons within the electric power industry and community with a high level of
technical expertise and be based on sound technical and engineering criteria. It should be based on actual data and
lessons learned from past operating incidents, where appropriate. The process for ERO approval of a proposed
Reliability Standard should be fair and open to all interested persons.
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a GMD event. While entities have flexibility in developing individual plans based on several
factors, the Reliability Coordinator will ensure proper coordination between responsible entities
during development, maintenance, and implementation.
2.
Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply.3
The proposed Reliability Standard is clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. The proposed Reliability
Standard applies to the Reliability Coordinators and Transmission Operators with Transmission
Operator Areas that include any power transformer with a high side wye-grounded winding with
a terminal voltage greater than 200 kV. The proposed Reliability Standard clearly articulates the
actions that such entities must take to comply with the standard.
3.
A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment. The assignment of the severity level for each VSL is consistent with the
corresponding requirement and the VSLs should ensure uniformity and consistency in the
determination of penalties. The VSLs do not use any ambiguous terminology, thereby
supporting uniformity and consistency in the determination of similar penalties for similar
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
2
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violations. For these reasons, the proposed Reliability Standard includes clear and
understandable consequences in accordance with Order No. 672.
4.
A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non
preferential manner. 5
The proposed Reliability Standard contains Measures that support each Requirement by
clearly identifying what is required and how the Requirement will be enforced. The Measures
are as follows:
M1. Each Reliability Coordinator shall have a current GMD
Operating Plan meeting all the provisions of Requirement R1;
evidence such as a review or revision history to indicate that the
GMD Operating Plan has been maintained; and evidence to show
that the plan was implemented as called for in its GMD Operating
Plan, such as dated operator logs, voice recordings, or voice
transcripts.
M2. Each Reliability Coordinator shall have evidence such as
dated operator logs, voice recordings, transcripts, or electronic
communications to indicate that forecasted and current space
weather information was disseminated as stated in its GMD
Operating Plan.
M3. Each Transmission Operator shall have a GMD Operating
Procedure or Operating Process meeting all the provisions of
Requirement R3; evidence such as a review or revision history to
indicate that the GMD Operating Procedure or Operating Process
has been maintained; and evidence to show that the Operating
Procedure or Operating Process was implemented as called for in
its GMD Operating Procedure or Operating Process, such as dated
operator logs, voice recordings, or voice transcripts.
These measures help provide clarity regarding how the Requirements will be enforced,
and help ensure that the Requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party.
5
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
3
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5.
Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design.6
The proposed Reliability Standard achieves its reliability goals effectively and efficiently
in accordance with Order No. 672. Responsible entities have flexibility in developing individual
Operating Plans, Operating Procedures, and Operating Processes. Several factors unique to each
entity may be considered during development, including geography, geology, and system
topology.
6.
Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed Reliability Standard contains significant reliability
benefits for the Bulk-Power System. The provisions of the proposed Reliability Standard raise
the level of preparedness among responsible entities by requiring the development, maintenance,
and implementation of Operating Plans, Operating Procedures, and Operating Processes
designed to mitigate the potentially severe impacts of a GMD on the Bulk-Power System.
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
4
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7.
Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard.8
The proposed Reliability Standard applies consistently throughout North America and
does not favor one geographic area or regional model.
8.
Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.9
Proposed Reliability Standard EOP-010-1 has no undue negative impact on competition.
The proposed Reliability Standard requires the same performance by each of the applicable
Functional Entities in the development of Operating Plans, Operating Processes, and Operating
Procedures.
The proposed Reliability Standard does not unreasonably restrict the available
transmission capability or limit use of the Bulk-Power System in a preferential manner. The
Requirements in the proposed Reliability Standard are designed to meet important reliability
goals in the event of a GMD—an event that poses a unique threat to the Bulk-Power System—
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.
5
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before, during, and after the event. Responsible entities are able to develop their own plans to
ensure those goals can be met.
9.
The implementation time for the proposed Reliability Standard is reasonable.10
The proposed effective date for the standard are just and reasonable and appropriately
balance the urgency in the need to implement the standard against the reasonableness of the time
allowed for those who must comply to develop necessary procedures, software, facilities,
staffing or other relevant capability. This will allow applicable entities adequate time to ensure
compliance with the Requirements. The proposed effective date is explained in the proposed
implementation plan, attached as Exhibit B.
10.
The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI-accredited processes for developing and approving Reliability
Standards. Exhibit H includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the standard drafting team
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.
6
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were properly noticed and open to the public. The initial and recirculation ballots both achieved
a quorum and exceeded the required ballot pool approval levels.
11.
NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of
this proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12.
Proposed Reliability Standards must consider any other appropriate factors.13
No other negative factors relevant to whether the proposed Reliability Standard is just
and reasonable were identified.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we
will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
7
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Exhibit D
White Paper Supporting Network Applicability
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators and Transmission Operators with networks
that contain power transformers with high side grounded wye windings above 200 kV. The drafting team
concluded that this is the minimum network voltage for which a reliability benefit can be expected from
the application of GMD Operating Procedures. This lower-bound threshold is consistent with operating
experience and modeling guidance provided in the literature, as explained below.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779.
Justification
Because transmission line resistance decreases by a factor of 10 from 69 kV to 765 kV and lower voltage
lines tend to be shorter (115 kV lines are typically less than 15 miles in length), the resulting
geomagnetically-induced current (GIC) generated by lines rated less than 200 kV are significantly less than
those of higher voltages and are typically ignored in GIC analysis. Conversely, using a voltage threshold
higher than 200 kV, such as 345 kV, for a lower-bound threshold could potentially create a reliability gap
by excluding a portion of the network that can be significantly affected by GMD. Results of sensitivity
analysis conducted by the drafting team are presented in the appendix. It shows that the GIC contribution
from the 230 kV portion of the network can result in system impacts during a GMD event.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Definition Considerations
Key parameters in the definition of a network for assessing GMD impacts are:
• Transformer grounding and core construction
o Only wye-grounded power transformer windings provide a path for GIC
o Transformer core construction (e.g., single-phase, three-phase, autotransformer) has an
effect on the magnitude of var absorption and generated harmonics. Single-phase
transformers are more susceptible to half-cycle saturation due to GIC relative to threephase 3-leg units; however, the var absorption in 3-legged three-phase core units cannot
be neglected.
o Regardless of core construction, all grounded wye transformers have an effect in the
distribution of GIC in the network
• System topology
• Geographical location
• Resistance values of the elements of the DC network used to evaluate GIC distribution within the
network
o Transmission line resistances per unit length increase as the voltage level decreases (see
typical values in Table 1). (With the resistances shown in Table 1, the maximum neutral
GIC contributed by a single 230 kV circuit is of the order of 30 A, as opposed to 75 A for a
single 345 kV circuit.)
Selection of a network where the cut off is selected on the basis of wye-grounded power
transformers with HV terminals > 200 kV
•
•
•
Almost all peer-reviewed studies on the effects of GIC include networks > 200 kV [1-13].
When lower voltage levels are included, the effects of including network elements < 200 kV are in
most cases minimal [9]. (The Appendix shows an example of the effects of the inclusion/exclusion
of the 115 kV network.)
The absorption of reactive power in a saturated transformer depends on the system operating
voltage and GIC. It does not depend on the nameplate rating of the transformer. In the case of
single-phase power transformers, var absorption and harmonic generation are very insensitive to
air-core reactance [11].
TABLE 1
TYPICAL NETWORK RESISTANCES FOR DIFFERENT VOLTAGE-LEVEL POWER GRIDS IN NORTH AMERICA
System
Voltage Levels
(kV)
230
345
500
735
DC Resistances
of the
Transformers
(ohm)
0.692
0.356
0.195
0.159
Grounding
Resistances of
the Substations
(ohm)
0.563
0.667
0.125
0.258
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
DC Resistances
of the
Transmission
lines (ohm/km)
0.072
0.037
0.013
0.011
2
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•
Reactive power absorption of a saturated transformer is proportional to its HV voltage rating.
Transformers < 200 kV have a relatively lower influence in the reactive power balance of the
system (see Figure 1).
90
80
Q (Mvar)
70
60
500 kV
50
230 kV
40
115 kV
30
20
10
0
0
50
100
150
200
250
GIC (A/phase)
Figure 1: Reactive power absorption of a single-phase transformer vs. GIC
System Impact Considerations
A key element in a GMD event is the absorption of reactive power of high side wye-grounded
transformers experiencing half-cycle saturation.
•
•
•
In many jurisdictions bulk power transmission includes voltages > 200 kV. Tripping a transformer
with high side voltage > 200 kV or reconfiguring > 200 kV circuits can impose serious constraints on
operating limits; therefore, such operating scenarios must be considered in GMD impact studies.
Generator step-up transformers are typically situated at electrical end points of the network
where GIC tends to be highest. GSUs with high side voltages > 200 kV are not uncommon. On the
other hand, GIC injected by circuits < 200 kV is limited because of the higher resistances of GSUs
connected to < 200 kV networks
Autotransformers are often used in networks above > 200 kV. The flow of GIC depends heavily on
the relative resistances of various network elements and the geographical orientation of nearby
transmission lines [14]. Considering a 500/230 kV autotransformer with one 500 kV and one 230
kV circuit, modelling GIC flow without taking into consideration the 230 kV circuit results in GIC
overestimation between 20% and 30%. In a more complex configuration, the estimated GIC
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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•
•
ignoring the 230 kV circuits can over or underestimate GIC and the effects of GIC in transformers
significantly. The appendix shows an example of this effect.
From the point of view of GIC distribution in the network, transformer vulnerability is not a
consideration. Including only transformers with high side windings > 300 kV would result in
unrealistic GIC flow assessments (see Appendix)
In systems where the bulk transmission voltages are 230 kV and 500 kV, neglecting circuits rated
less than 300 kV would misrepresent GIC flows and var absorption, especially because GIC flowthrough in 500 kV autotransformers would be neglected (see Appendix).
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Appendix
This Appendix describes two examples where:
• The exclusion of 230 kV circuits at a station with 500/230 kV autotransformers cause significant
errors in the estimation of GIC effects.
• The inclusion/exclusion of the 161 kV and 115 kV networks in a large utility within the Eastern
Interconnect has minimal impact on the estimation of the effects of GIC in the system
Example 1: Exclusion of 230 kV circuits in a 500/230 kV transmission station
The distribution of GIC in a network, for a given geomagnetic latitude and earth structure, depends on a
number of factors such as resistances of various circuit elements, induced voltages and network topology.
There are times when a complex network topology can lead to non-intuitive results, such as the presence
of a series capacitor causing an increase of GIC in a transformer.
To illustrate, consider the topology of the circuits connected to Transmission Station (TS) shown in Fig. A1.
If a transmission circuit is sufficiently long it can be represented by a constant current source (since both
induced voltage and line resistance are proportional to line length). In the case of a 500 kV circuit, GIC
tends to be fairly constant for lengths > 150 km. A simplified representation is shown in Fig A2. The
station has several autotransformers which have been lumped into a single equivalent autotransformer.
The series capacitor bank is assumed to be out of service (bypassed).
Currents I1 and I2 represent the GIC contribution of the 500 kV circuits to the HV bus. Then,
I 3 = I1 − I 2
(A.1)
where I3 is the total contribution of the 500 kV circuits to the series winding. The total contribution to the
common winding is given by
Ig = I 3 + I 4 + I 5 + I 6 − I 7
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
(A.2)
5
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I1
Series capacitor
500 kV
230 kV
I4
230 kV
I5
I6
TS
230 kV
I2
I7
230 kV
500 kV
Fig. A1: HV transmission lines connecting to Essa TS.
I1
I4
I5
HV
I2
I3
LV
I7
Ig
I6
Fig. A2: Circuit representation of induced geoelectric fields and equivalent transformer representation.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Let us assume that the earth can be represented by a laterally-uniform earth model, and that the 500 kV
circuits are in the same or similar orientation geographically with the same resistance per unit length, so
that the injected GIC I1 and I2 are nearly identical (see Fig. A1). Then I3 will be small or zero and only the
230 kV circuits will contribute to the current in the transformer common winding Ig. If the 230 kV circuits
were excluded, (i.e., I4 = I5 = I6 = I7 = 0) then I3 = Ig would be very small and the estimated effects of GIC
on the autotransformer would be minimal.
If the 500 kV series capacitor bank in Fig. A1 is placed in service, then I1 = 0 and I2 = I3. The commonwinding GIC is now equal to the sum of the GIC contributed by the 230 kV circuits and the remaining 500
kV circuit. Depending on the relative values of the contributions, the net GIC through the transformer
may increase or decrease. Simulations show that in the network shown in Figure A1 when the series
capacitors are in service, the effective GIC through the transformer increases by a factor of 30. This is not
a general result, but rather a consequence of Kirchhoff’s current law and a particular system topology.
If the series capacitor bank is in service and the 230 kV circuits are not taken into consideration all the GIC
from the remaining 500 kV circuit would flow into the autotransformer and describe a completely
different situation from in terms of the saturation of the autotransformer.
The cases described above were simulated with a GIC analysis tool and summarized in Table A1. Note
that there are two 500/230 kV autotransformers in service in this simulation.
Table A1: Summary of the Effects of 230 kV Circuits in a Station
with Two 500/230 kV Autotransformers
Geoelectric
field
5 V/km
Transformer
GIC/phase
(A/phase)
I1 (A/phase)
I2 (A/phase)
Incremental
metallic hot spot
temperature (C°)
var absorption
(Mvar)
THD (%)
230 kV and
500 kV
500 kV Series
caps in service
230 kV and
500 kV
500 kV Series
caps bypassed
No 230 kV
500 kV Series
caps in service
No 230 kV
500 kV Series
caps bypassed
99.9
2.8
127
5.5
0
146.8
365
334
0
254
338
349
89
1.6
60
7.6
128
14
151
12.5
17
2.5
18
2.2
The conclusion from this example is that it is not always possible to make generalizations in a network of
relatively complex topology. While it is true that a series capacitor blocks GIC in the transmission line
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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where it is employed, it does not necessarily reduce GIC in system transformers. Furthermore, not taking
into account the effects of the 230 kV circuits in this network would lead to inaccurate conclusions, such
as a 33% underestimation of the hot spot temperature rise 1.
Example 2: Effects of the inclusion/exclusion of circuits below 200 kV
A portion of the Eastern Interconnect that contains 500 kV, 230 kV, 161 kV, and 115 kV facilities was
modeled using PowerWorld software. When the GIC contribution of the 161 kV and 115 kV circuits was
excluded, the effects on the network above 200 kV where found to be minimal. Table A2 summarizes the
effects of including/excluding GIC contributions from the 161 kV and 115 kV network assuming a 5 V/km
East-West geoelectric field. The differences in the results assuming a North-South geoelectric field are
very similar, and are not reproduced in here.
Table A2: GIC Effects on the Network Above 200 kV Assuming an
East-West 5 V/km Geoelectric Field
Including 115
kV
Maximum transformer GIC (A/phase)
134.65
Average transformer GIC (A/phase)
13.79
Maximum transformer var absorption 150.3
(Mvar)
Average transformer var absorption 7.16
(Mvar)
Minimum bus voltage (pu)
0.98204
Average bus voltage (pu)
1.01858
Total system var loss due to GIC (Mvar)
3,935
Excluding 115
kV
133.78
13.46
149.5
Difference
0.6 (%)
2.4 (%)
0.7 (%)
7.08
1.1 (%)
0.98548
1.01897
3,801
0.4 (%)
0.04 (%)
3.4 (%)
These results are consistent with observations made in peer-reviewed technical publications such as [9].
1
Hot spot heating was estimated using the methodology described in [15]
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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References
[1] Boteler, D., Bui-Van, Q., & Lemay, J. (1994). Directional sensitivity to geomagnetically induced currents of the
Hydro-Quebec 735 kV power system. Power Delivery, IEEE Transactions on, 9(4), 1963-1971.
[2] Boteler, D., Watanabe, T., Shier, R., & Horita, R. (1982). Characteristics of Geomagnetically Induced Currents in
the B. C. Hydro 500 kV System. Power Apparatus and Systems, IEEE Transactions on, PAS-101(6), 1447-1456.
[3] Mäkinen, T. (1992). Geomagnetically induced currents in the Finnish power transmission system. Helsinki,
Finland: Finnish Meteorological Institute.
[4] Mohan, N., Albertson, V., Speak, T., Kappenman, K., & Bahrman, M. (1982). Effects of Geomagnetically-Induced
Currents on HVDC Converter Operation. Power Apparatus and Systems, IEEE Transactions on, PAS-101(11), 44134418.
[5] Picher, P., Bolduc, L., Dutil, A., & Pham, V. (1997). Study of the acceptable DC current limit in core-form power
transformers. IEEE Transactions on Power Delivery, Vol 12, No1, 257-265.
[6] Pirjola, R. (2000). Geomagnetically induced currents during magnetic storms. Plasma Science, IEEE Transactions
on, 28(6), 1867-1873.
[7] Pirjola, R., & Boteler, D. (2006). Geomagnetically Induced Currents in European High-Voltage Power Systems.
Electrical and Computer Engineering, 2006. CCECE '06. Canadian Conference on (pp. 1263-1266). Ottawa, Canada:
IEEE.
[8] Pirjola, R., Liu, C.-m., & Liu, L.-g. (2010). Geomagnetically Induced Currents in electric power transmission
networks at different latitudes. Electromagnetic Compatibility (APEMC), 2010 Asia-Pacific Symposium on (pp. 699702). Beijing, China: IEEE.
[9] Prabhakara, F., Hannett, L., Ringlee, R., & Ponder, J. (1992). Geomagnetic effects modelling for the PJM
interconnection system. II. Geomagnetically induced current study results. Power Systems, IEEE Transactions on,
7(2), 565-571.
[10] Viljanen, A., Pirjola, R., Wik, M., Adam, A., Pracser, E., Sakharov, Y., et al. (2012). Continental scale modelling of
geomagnetically induced currents. J. Space Weather Space Clim., 3, A171-A1711.
[11] Walling, R., & Khan, A. (1991). Characteristics of transformer exciting-current during geomagnetic disturbances.
Power Delivery, IEEE Transactions on, 6(4), 1707-1714.
[12] Viljanen, A., & Pirjola, R. (1994). Geomagnetically Induced Currents in the Finnish High-Voltage
Power System: A Geophysical Review. Netherlands: Surveys in Geophysics, 15, 383-408.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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[13] Wik, M., Viljanen, A., Pirjola, R., Pulkkinen, A., Wintoft, P., & Lundstedt, H. (2008). Calculation of
Geomagnetically Induced Currents in the 400 kV Power Grid in Southern Sweden. Space Weather, Vol. 6,
S07005, 1-11.
[14] Overbye, T. J., et al, “Power Grid Sensitivity Analysis of Geomagnetically Induced Currents”, IEEE
Transactions on Power Delivery, 2013, Accepted for inclusion in a future issue, Digital Object Identifier
10.1109/TPWRS.2013.2274624.
[15] 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
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Exhibit E
White Paper Supporting Functional Entity Applicability
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Functional Entity Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators (RC) and Transmission Operators (TOP) with
networks that contain power transformers with high side grounded wye windings above 200 kV. This
applicability is consistent with the NERC Functional Model and existing standards where both entities are
described as having responsibility and authority for reliable transmission operations within their scope.
The drafting team determined that Balancing Authorities (BA) should not be among the applicable
functional entities because there were no additional steps or tasks for a BA to perform beyond their
normal balancing functions to mitigate GMD events. The drafting team also determined that Generator
Operators (GOP) should not be among the applicable functional entities because any Operating
Procedures to mitigate the effects of GMD would need to be supported by an equipment-specific study
and is expected to require GMD monitoring equipment. Consistent with FERC Order No. 779, vulnerability
assessments and mitigation plans will be addressed in stage 2 of Project 2013-03 and applicability of stage
2 standards will be considered separately.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779. While the
applicability of the proposed stage 1 standard is limited to RCs and TOPs, other entities will be considered
for stage 2 as outlined in the Standards Authorization Request.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Justification for Applicable Functional Entities
Reliability Coordinator
The RC has responsibility and authority for reliable operation within the Reliability Coordinator Area
(RCA). The RC's scope includes a wide-area view with situational awareness of neighboring RCAs. The
NERC Functional Model states:
The Reliability Coordinator maintains the Real-time operating reliability of its Reliability
Coordinator Area and in coordination with its neighboring Reliability Coordinator's wide-area
view. The wide-area view includes situational awareness of its neighboring Reliability Coordinator
Areas. Its scope includes both transmission and balancing operations, and it has the authority to
direct other functional entities to take certain actions to ensure that its Reliability Coordinator
Area operates reliably.
The RC's authority is codified in IRO-001-1a which states:
R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions
to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions
shall be taken without delay, but no longer than 30 minutes.
R8. Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability
Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory
requirements. Under these circumstances, the Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity, or Purchasing-Selling Entity
shall immediately inform the Reliability Coordinator of the inability to perform the directive so that
the Reliability Coordinator may implement alternate remedial actions.
Including the RC as an applicable entity in EOP-010-1 provides the necessary coordination for planning
and real-time actions that is envisioned by the Functional Model and addresses Order No. 779 directives
to consider the coordination of Operating Procedures across regions by a functional entity with a widearea view.
Transmission Operator
Like the RC, the TOP has responsibility and authority for the reliable operation of the transmission system
within a specified area. According to the NERC Functional Model:
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
2
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The Transmission Operator is responsible for the Real-time operating reliability of the transmission
assets under its purview, which is referred to as the Transmission Operator Area. The Transmission
Operator has the authority to take certain actions to ensure that its Transmission Operator Area
operates reliably.
The TOP's authority is established in TOP-001-1a as follows:
R1. Each Transmission Operator shall have the responsibility and clear decision-making authority to
take whatever actions are needed to ensure the reliability of its area and shall exercise specific
authority to alleviate operating emergencies.
R3. Each Transmission Operator, Balancing Authority, and Generator Operator shall comply with
reliability directives issued by the Reliability Coordinator, and each Balancing Authority and
Generator Operator shall comply with reliability directives issued by the Transmission Operator,
unless such actions would violate safety, equipment, regulatory or statutory requirements. Under
these circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform
the directive so that the Reliability Coordinator or Transmission Operator can implement alternate
remedial actions.
The 2012 GMD Report contains web links for some TOP Operating Procedures to mitigate the effects of
GMD events. Recently the GMD Task Force developed Operating Procedure templates that provide a
technical resource for TOPs to use in developing procedures based on industry best practices. Included in
the templates are actions that could be employed to mitigate the effects of GMD, such as reduction of
equipment loading, increasing reactive reserves, reconfiguration of the system, recalling outages, and Load
shedding. The templates also describe indicators of GMD conditions that could be used as trigger
conditions for steps or tasks in an entity's Operating Procedures. Detailed study of system and equipment
impacts can improve Operating Procedures. However, some procedures can be put in place without system
studies to increase situational awareness and posture the system when a GMD event is forecasted.
Justification for Omitting Functional Entities
Balancing Authority
BAs are responsible for the Real-time balancing of the system. In order to carry out that responsibility,
BAs will dispatch generation, use regulation and other ancillary services, to keep Area Control Error (ACE)
within reasonable limits while maintaining system frequency. BAs will work with the TOP to adjust voltage
schedules or redispatch generation at the request of the TOP to ensure that the transmission system is
operated within thermal, voltage, and stability limits.
The BA can be expected to address GMD impacts through use of generation. However, the BA would not
initiate actions unilaterally during a GMD event and would instead respond to the direction of the TOP
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
and RC. As such, the independent actions that the BA would take are very limited, if any. For example, if
redispatch of generation or adjustment of voltage schedules were needed, the BA would not take those
actions without a request and the concurrence of the TOP and/or RC.
The RC and TOP will be preparing GMD Operating Plans, Operating Processes, and/or Operating
Procedures to address steps that each will be taken to address GMD impacts. Some of those steps will
require the BA to take action. As outlined above, the requirement for the BA to execute actions at the
request of the TOP or RC is clear. Given that the BA would only take action at the request of the TOP or
RC and that the required actions would be the same actions BAs take for other system events, the SDT
concludes that the BA should not be included as an applicable entity in EOP-010-1.
Generator Operator
GOPs are the functional entity that operate generating unit(s) and perform the functions of supplying
energy and reliability related services. They may be responsible for operating generator step up (GSU)
transformers that connect the generator to the transmission system. Some GSU transformers are
susceptible to geomagnetically-induced currents (GICs) during a GMD event, and operating actions are
used by some GOPs to mitigate system or equipment impacts.
An effective GOP GMD Operating Procedure to mitigate the effects of GMD would require:
1. GSU transformer study to determine expected GIC on the GSU high side neutral level at their site
(GIC/thermal rating study)
2. Ability to monitor GIC at the GSU high voltage wye-grounded winding neutral
Absent the above information, the GOP would not have the technical basis for taking steps on its own and
would instead take steps based on the RC or TOP’s Operating Plans, Processes, or Procedures. Therefore,
the SDT concludes that GOPs should be excluded as applicable entities in EOP-010-1.
Some GOPs already have GMD Operating Procedures for their equipment based on prior studies and/or
monitoring equipment. EOP-010-1 will not prohibit or interfere with a GOP's established procedure.
Furthermore, the RC and TOP will be preparing GMD Operating Plans and Operating Processes or
Procedures, respectively. Those will address steps that each will be taking to address GMD impacts,
which may include requiring one or more GOPs to take action. Existing standards provide obligations for
the GOP to execute actions when requested by the TOP or RC as described above.
Generator Owners (GOs) and GOPs are included in the Project 2013-03 Standards Authorization Request.
They will be considered for inclusion in Stage 2 standards, which will require applicable entities to conduct
vulnerability assessments and develop appropriate mitigation strategies. Such mitigation strategies could
include the development of Operating Procedures for applicable GOs and GOPs.
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Exhibit F
Analysis of Violation Risk Factors and Violation Security Levels
Violation Risk Factor and Violation Severity Level
Justifications
EOP-010-1 − Geomagnetic Disturbance Operations
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 EOP-010-1 – Geomagnetic Disturbance Operations.
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 Standard Drafting Team applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSL 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 Violation Risk Factors 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
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
2
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
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 Violation Risk Factor assignments and the main Requirement
Violation Risk Factor assignment.
Guideline (3) – Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk Factor 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
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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
3
Violation severity levels 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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
5
VRF Justifications – EOP-010-1, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to implement a GMD Operating Plan when warranted by conditions could directly affect the
electrical state or the capability of the Bulk Electric System (BES). However, failure to implement a
GMD Operating Plan is unlikely to lead to BES instability, separation, or cascading failures. The
Reliability Coordinator and applicable entities are responsible for maintaining the reliability of the BES
under all circumstances. Failure to develop or maintain a GMD Operating Plan could, under
anticipated conditions, directly and adversely affect the electrical state or capability of the Bulk
Electric System. However, failure to develop or maintain a GMD Operating Plan is unlikely to lead to
BES instability, separation, or cascading failures, or to hinder restoration to normal conditions. This
VRF reflects the drafting team's view of the importance of having coordinated GMD Operating
Procedures and the RC's role in the planning and operations time horizons.
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. The requirement uses Parts to identify the items to be included in a GMD
Operating Plan. The VRF for this requirement is consistent with Requirement R3 with regard to
relative risk.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with IRO 014-1 Requirement R1, which requires the Reliability Coordinator to have Operating
Procedures, Processes, or Plans in place to support interconnection reliability. The drafting team
believes the reliability objective of IR0-014-1 Requirement R1 is most comparable to the proposed
Requirement R1.
Guideline 4- Consistency with NERC Definitions of VRFs. A Violation Risk Factor of Medium is
consistent with NERC VRF definition. Failure to implement a GMD Operating Plan when warranted by
conditions could directly affect the electrical state or the capability of the Bulk Electric System (BES).
However, failure to implement a GMD Operating Plan is unlikely to lead to BES instability, separation,
FERC VRF G3 Discussion
FERC VRF G4 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
6
VRF Justifications – EOP-010-1, R1
FERC VRF G5 Discussion
or cascading failures. The Reliability Coordinator and applicable entities are responsible for
maintaining the reliability of the BES under all circumstances. Failure to develop or maintain a GMD
Operating Plan could, under anticipated conditions, directly and adversely affect the electrical state
or capability of the Bulk Electric System. However, failure to develop or maintain a GMD Operating
Plan is unlikely to lead to BES instability, separation, or cascading failures, or to hinder restoration to
normal conditions. This VRF reflects the drafting team's view of the significance of the RC's role in
coordinating GMD Operating Procedures in the planning and operations time horizons.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. The assigned risk
level reflects the most important objective of the requirement.
Proposed VSLs – EOP-010-1, R1
Lower
The Reliability Coordinator had a
GMD Operating Plan, but failed
to maintain it.
Moderate
N/A
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
High
The Reliability Coordinator's
GMD Operating Plan failed to
include one of the required
elements as listed in
Requirement R1, parts 1.1 or 1.2
Severe
The Reliability Coordinator did
not have a GMD Operating Plan
OR
The Reliability Coordinator failed
to implement a GMD Operating
Plan within its Reliability
Coordinator Area
7
VSL Justifications – EOP-010-1, R1
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 VSL describes degrees of noncompliant performance in an
incremental manner.
There is no prior compliance obligation related to the subject of this standard.
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.
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
8
with the Corresponding
Requirement
The proposed VSL is not based on 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 – EOP-010-1, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to disseminate forecasted and current space weather information could directly and adversely
affect the electrical state or capability of the Bulk Electric System during a GMD event. However, failure
to disseminate forecasted and current space weather information is unlikely to lead to BES instability,
separation, or cascading failures. The Reliability Coordinator and applicable entities are responsible for
maintaining the reliability of the BES under all circumstances. This requirement and VRF reflects the
drafting team's view of the significance of consistent space weather information for coordination of
GMD Operating Procedures in each Reliability Coordinator Area and maintains responsibility for
providing this information on the Reliability Coordinator as established in IRO-005-3.1a.
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 and a
single VRF.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with IRO-008-1 Requirement R3 which requires the Reliability Coordinator to share information with
specific entities that are expected to take operational actions when a potential Interconnection
FERC VRF G3 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
9
VRF Justifications – EOP-010-1, R2
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Reliability Operating Limit violation is anticipated. Dissemination of space weather forecast information
can be considered a similar information sharing activity with an impact that would not exceed IRO-008-1
Requirement R3.
Guideline 4- Consistency with NERC Definitions of VRFs. Failure to disseminate forecasted and current
space weather information could directly and adversely affect the electrical state or capability of the
Bulk Electric System during a GMD event. However, failure to disseminate forecasted and current space
weather information is unlikely to lead to BES instability, separation, or cascading failures. The Reliability
Coordinator and applicable entities are responsible for maintaining the reliability of the BES under all
circumstances. This requirement and VRF reflects the drafting team's view of the significance of
consistent space weather information for coordination of GMD Operating Procedures in each Reliability
Coordinator Area and maintains responsibility for providing this information on the Reliability
Coordinator as established in IRO-005-3.1a.
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 – EOP-010-1, R2
Lower
N/A
Moderate
N/A
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
High
N/A
Severe
The Reliability Coordinator failed
to disseminate forecasted and
current space weather
information to all functional
entities identified as recipients in
the Reliability Coordinator's
GMD Operating Plan.
10
VSL Justifications – EOP-010-1, 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
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
Consistent with NERC's VSL Guidelines. The drafting team believes that a single VSL is most appropriate
for describing noncompliant performance of the requirement. Dissemination of space weather
information will most likely be accomplished using automated communication systems such as all-call or
electronic distribution lists. As a result the RC's compliance will be evaluated on a binary basis for
implementing a notification system to disseminate space weather information.
The current level of compliance is not lowered with the proposed VSL. IRO-005-3.1a requirement R3
provided a similar compliance obligation without a FERC-approved VSL.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL assignment category for a binary requirement is consistent.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
11
VSL Justifications – EOP-010-1, R2
Ambiguous Language
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 number of violations.
VRF Justifications – EOP-010-1, R3
Proposed VRF
NERC VRF Discussion
Medium
Failure to implement a GMD Operating Procedure or Operating Process when warranted by conditions
could directly affect the electrical state or the capability of the Bulk Electric System (BES). However, this
failure is unlikely to lead to BES instability, separation, or cascading failures. The Transmission Operator
and other applicable entities are responsible for maintaining the reliability of the BES under within their
respective areas in all circumstances. Failure to develop or maintain a GMD Operating Procedure or
Operating Process could, under anticipated conditions, directly and adversely affect the electrical state
or capability of the Bulk Electric System. However, this failure is unlikely to lead to BES instability,
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
12
VRF Justifications – EOP-010-1, R3
separation, or cascading failures, or to hinder restoration to normal conditions. This VRF reflects the
drafting team's view of the importance of developing and maintaining coordinated and predetermined
operating procedures or processes in the planning horizon, and for implementing the operating
procedures or processes when conditions warrant in the operations time horizon.
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. The requirement uses Parts to identify the items to be included in a GMD
Operating Procedure or Operating Process. The VRF for this requirement is consistent with Requirement
R1 with regard to relative risk.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with EOP 001-2.1b, requirement R2.2 which requires the Transmission Operator to develop, maintain,
and implement plans to mitigate operating emergencies on the transmission system. Additionally, it is
consistent with IRO 014-1 Requirement R1, which requires the Reliability Coordinator to have Operating
Procedures, Processes, or Plans in place to support interconnection reliability. Although the functional
entities are different, the reliability objective of IR0-014-1 Requirement R1 is comparable to the
proposed Requirement R3.
Guideline 4- Consistency with NERC Definitions of VRFs. Failure to implement a GMD Operating
Procedure or Operating Process when warranted by conditions could directly affect the electrical state
or the capability of the Bulk Electric System (BES). However, this failure is unlikely to lead to BES
instability, separation, or cascading failures. The Transmission Operator and other applicable entities are
responsible for maintaining the reliability of the BES under within their respective areas in all
circumstances. Failure to develop or maintain a GMD Operating Procedure or Operating Process could,
under anticipated conditions, directly and adversely affect the electrical state or capability of the Bulk
Electric System. However, this failure is unlikely to lead to BES instability, separation, or cascading
failures, or to hinder restoration to normal conditions. This VRF reflects the drafting team's view of the
FERC VRF G3 Discussion
FERC VRF G4 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
13
VRF Justifications – EOP-010-1, R3
FERC VRF G5 Discussion
importance of developing and maintaining coordinated and predetermined operating procedures or
processes in the planning horizon, and for implementing the operating procedures or processes when
conditions warrant in the operations time horizon.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. The assigned risk
level reflects the most important objective of the requirement.
Proposed VSLs – EOP-010-1, R3
Lower
The Transmission Operator had a
GMD Operating Procedure or
Operating Process, but failed to
maintain it.
Moderate
The Transmission Operator's
GMD Operating Procedure or
Operating Process failed to
include one of the required
elements as listed in
Requirement R3, parts 3.1
through 3.3.
High
The Transmission Operator's
GMD Operating Procedure or
Operating Process failed to
include two or more of the
required elements as listed in
Requirement R3, parts 3.1
through 3.3.
Severe
The Transmission Operator did
not have a GMD Operating
Procedure or Operating Process
OR
The Transmission Operator failed
to implement its GMD Operating
Procedure or Operating Process.
VSL Justifications – EOP-010-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
There is no prior compliance obligation related to the subject of this standard.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
14
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
Cumulative Number of
Violations
The proposed VSL is not based on 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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
15
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
16
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Exhibit G
Analysis of Commission Directives
Commission Directives in Order No. 779, Reliability Standards for Geomagnetic Disturbances, 143 FERC ¶ 61,147 (2013)
Stage 1, EOP-010-1
Order No. 779
Citation
P 36
Directive/Guidance
The Commission directs NERC to submit, within six months of the effective
date of this Final Rule, one or more Reliability Standards requiring owners
and operators of the Bulk-Power System to develop and implement
operational procedures to mitigate the effects of GMDs consistent with the
reliable operation of the Bulk-Power System.
Resolution in EOP-010-1
Requirement R1 requires Reliability
Coordinators to develop, maintain, and
implement a GMD Operating Plan that
coordinates GMD Operating Procedures or
Operating Processes within its Reliability
Coordinator Area.
Requirement R3 requires Transmission
Operators to develop, maintain, and implement a
GMD Operating Procedure or Operating Process
to mitigate the effects of GMD events on the
reliable operation of its respective system.
P 38
The Commission is not directing NERC to develop Reliability Standards
that include specific operational procedures. Instead, as proposed in the
NOPR, the Reliability Standards should include a mechanism that requires
responsible entities to develop and implement operational procedures
because owners and operators of the Bulk-Power System are most familiar
with their own equipment and system configurations. In addition, we do not
expect that owners and operators of the Bulk-Power System will necessarily
develop and implement the same operational procedures. Instead, the
Reliability Standards, rather than include “one-size-fits-all” Requirements,
should allow responsible entities to tailor their operational procedures based
on the responsible entity’s assessment of entity-specific factors, such as
geography, geology, and system topology, identified in the Reliability
Standards. In addition, as we stated in the NOPR, the coordination of
operational procedures across regions is an important issue that should be
considered in the NERC standards development process.68 The coordination
Analysis of the applicable functional entities is
provided in a white paper posted on the project
page.
(http://www.nerc.com/pa/Stand/Pages/Project2013-03-Geomagnetic-DisturbanceMitigation.aspx)
EOP-010-1 is not prescriptive and allows entities
to tailor their Operational Procedures or
Operating Processes based on the responsible
entity’s assessment of entity-specific factors,
such as geography, geology, and system
topology.
Requirement R1 addresses coordination and
requires Reliability Coordinators to develop,
maintain and implement a GMD Operating Plan
that coordinates GMD Operating Procedures or
Operating Processes within its Reliability
Coordinator Area.
The coordination of Operating Procedures and
Order No. 779
Citation
Directive/Guidance
Resolution in EOP-010-1
of operational procedures across regions and data sharing might be overseen
by planning coordinators or another functional entity with a wide-area
perspective.69 The NERC standards development process, as stated in the
NOPR, should also consider operational procedures for restoring GMDimpacted portions of the Bulk-Power System that take into account the
potential for damaged equipment that could be de-rated or out-of-service for
an extended period of time.
2
Operating Processes across regions is addressed
through existing Reliability Standards.
EOP-005 (System Restoration from Blackstart
Resources) and EOP-006 (System Restoration
Coordination) address Bulk-Power System
restoration following a Disturbance. These plans
are expected to be effective for restoration
following any unplanned event. A duplicative
requirement was not included in EOP-010-1.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Exhibit H
Summary of Development History and Complete Record of Development
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Exhibit H—Summary of the Reliability Standard Development Proceeding and Complete
Record of Development of Proposed Reliability Standard EOP-010-1
The development record for proposed Reliability Standard EOP-010-1 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. 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
members is included in Exhibit I.
II.
Standard Development History
A. Standard Authorization Request Development
A Standard Authorization Request (“SAR”) was submitted on June 12, 2013 and
approved by the Standards Committee (“SC”) on June 21, 2013.
B. First Posting – Formal Comment Period and Ballot
Proposed Reliability Standard EOP-010-1 was posted for a 45-day formal public
comment period and ballot from June 27, 2013 through August 12, 2013. There were 85 sets of
responses, including comments from approximately 225 individuals from approximately 140
companies representing all 10 industry segments. Proposed Reliability Standard EOP-010-1
received a quorum of 76.32% and an approval 62.74%.
The standard drafting team considered stakeholder comments and made the following
changes to proposed Reliability Standard EOP-010-1 based on those comments:
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2006).
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
A new Requirement R2 was added to the proposed Reliability Standard, which would require
the Reliability Coordinator (“RC”) to disseminate space weather forecast information to
Transmission Operators (TOP) in their Reliability Coordinator Area. IRO-005-3.1a
Requirement R3 provided for that obligation, however, the NERC Board approved IRO-0054 which resulted in retirement of the requirement. The new Requirement R2 in EOP-010-1
will maintain the RC’s responsibility for providing space weather forecast information. The
implementation plan includes guidance for making the new Requirement R2 effective to
avoid a situation where both IRO-005-3.1a Requirement R3 and EOP-010-1 Requirement R2
are effective at the same time.
In response to stakeholder comments that certain Requirements met Paragraph 81 criteria,
administrative requirements for reviewing of GMD Operating Plans and Procedures within a
36-month period and for having a copy in the control room were removed.
Balancing Authorities (“BA”) have been removed from the applicable functional entities
because there are no additional steps or tasks for a BA to perform beyond their normal
balancing functions to mitigate GMD events. The BA is not expected to initiate specific
mitigating actions during a GMD event and would instead respond to the direction of the
TOP and RC. Existing Reliability Standards provide the required authority for action. A
whitepaper with the standard drafting team's analysis was posted on the project page.
The applicable TOP was been clarified to include only those that operate power transformers
with a high side wye-grounded winding with terminal voltage greater than 200 kV. This
applicability statement describes the functional entity in terms of the assets that they operate,
which could include non-BES assets. The applicability statement is not intended to define
equipment to be protected by the Operating Procedures. The standard drafting team views
200 kV as the minimum network voltage for which a reliability benefit can be expected from
the application of GMD Operating Procedures. A whitepaper with the drafting team's
analysis was posted on the project page.
Although some stakeholders suggested that Generator Operators (GOP) be added to the
proposed Reliability Standard as applicable entities, the standard drafting team maintained
that GOP Operating Procedures designed to mitigate the effects of GMD would need to be
supported by an equipment-specific study and might require the use of GMD monitoring
equipment. Because it is not reasonable to assume that all GOP have such studies or
monitoring equipment, GOP have not been added to proposed Reliability Standard EOP-0101. Consistent with Commission Order No. 779, vulnerability assessments and mitigation
plans will be addressed in stage 2 of Project 2013-03, and Generator Owners (GO) and GOP
will be considered for applicability with Stage 2. A whitepaper with the standard drafting
team's analysis supporting the applicability of proposed Reliability Standard EOP-010-1 was
posted on the project page.
Some stakeholders also commented that the six-month implementation period was too short.
The drafting team was sympathetic to the challenge of completing the necessary coordination
in a six-month time period. However, this implementation period was suggested in Order
No. 779 and the standard drafting team lacks strong justification for a specific longer period.
Several changes in language were made to improve the clarity of requirements and measures.
C. Second Posting – Formal Comment Period and Additional Ballot
Proposed Reliability Standard EOP-010-1 was posted for a 45-day formal public
comment period from September 4, 2013 through October 21, 2013. There were 37 sets of
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
responses, including comments from approximately 120 individuals from approximately 80
companies representing 9 of the 10 industry segments. Proposed Reliability Standard EOP-0101 received a quorum of 77.58% and an approval 88.75%.
The standard drafting team considered stakeholder comments and made the following
changes to proposed Reliability Standard EOP-010-1 based on those comments:
In Section 5 (Background), capitalized "Protection System" because it is defined in the
NERC Glossary of Terms.
In Requirement R1, revised the Requirement to include the term “Operating Process” in R1
and R1 part 1.2 and changed language to be consistent with Requirement R3. The revised
Requirement with highlighted changes is as follows:
o R1. Each Reliability Coordinator shall develop, maintain, and implement a GMD
Operating Plan that coordinates GMD Operating Procedures or Operating Processes
within its Reliability Coordinator Area. At a minimum, the GMD Operating Plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning,
Operations Planning, Same-day Operations, Real-time Operations]
1.1 A description of activities designed to mitigate the effects of GMD events
on the reliable operation of the interconnected transmission system within the
Reliability Coordinator Area.
1.2 A process for the Reliability Coordinator to review the GMD Operating
Procedures or Operating Processes of Transmission Operators within the its
Reliability Coordinator Area.
In Measure M1, inserted the word “current” to align with NERC guidelines for writing
Measures to support this type of Requirement. The revised Measure with the highlighted
change is as follows:
o M1. Each Reliability Coordinator shall have a current GMD Operating Plan meeting
all the provisions of Requirement R1; evidence such as a review or revision history to
indicate that the GMD Operating Plan has been maintained; and evidence to show
that the plan was implemented as called for in its GMD Operating Plan, such as dated
operator logs, voice recordings, or voice transcripts.
In Requirement R2, clarified that the Reliability Coordinator shall disseminate forecasted and
current space weather information to functional entities identified as recipients in the
Reliability Coordinator's GMD Operating Plan. The revised requirement with highlighted
change is as follows:
o R2. Each Reliability Coordinator shall disseminate forecasted and current space
weather information to functional entities identified as recipients as specified in the
Reliability Coordinator's GMD Operating Plan. [Violation Risk Factor: Medium]
[Time Horizon: Same-day Operations, Real-time Operations]
In Requirement R3, inserted “GMD”, so that the phrase "GMD Operating Procedure or
Operating Process" would be consistent with Requirement R1. The revised Requirement is
as follows:
o R3. Each Transmission Operator shall develop, maintain, and implement a GMD
Operating Procedure or Operating Process to mitigate the effects of GMD events on
the reliable operation of its respective system. At a minimum, the Operating
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Procedure or Operating Process shall include: [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning, Operations Planning, Same-day Operations,
Real-Time Operations]
A clarifying change was made to the Implementation Plan to conform to the effective date
language in the proposed Reliability Standard, which was changed in the prior draft in
response to concerns raised by Canadian entities.
D. Final Ballot
Proposed Reliability Standard EOP-010-1 was posted for a 10-day final ballot period on
October 25, 2013 through November 4, 2013. The proposed Reliability Standard received a
quorum of 86.90% and an approval rating of 91.95%.
E. Board of Trustees Approval
Proposed Reliability Standard EOP-010-1 was approved by the NERC Board of Trustees
on November 7, 2013.
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Program Areas & Departments > Standards > Project 2013-03 Geomagnetic Disturbance Mitigation
Project 2013-03 Geomagnetic Disturbance Mitigation
Related Files
Status:
EOP-010-1 was approved by industry and will proceed to the NERC Board of Trustees for adoption at its November 2013 meeting.
Background:
FERC issued order 779 in May 2013 directing NERC to develop reliability standards to address the potential impact of geomagnetic disturbances (GMDs) on the reliability operation of the Bulk-Power
System. Since 2010, industry has taken steps to address the GMD risk scenario identified in the 2010 High Impact Low Frequency (HILF) Event joint report through the Geomagnetic Disturbance (GMD)
Task Force, which is comprised of industry representatives, government partners, and GMD experts. The GMD Task Force published an interim report on the effects of GMD on the Bulk-Power System in
April 2012 and provided recommendations to manage risk. The task force’s current project is focused on providing tools for system operators and planners to assess GMD effects on the system and
implement mitigating strategies when needed.
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.
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, geomagnetically-induced 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.
The project will develop requirements for registered entities to employ strategies that mitigate risks of instability, uncontrolled separation and Cascading caused by GMD in two stages as directed in order
779:
1. Stage 1 standard(s) will require applicable registered entities to develop and implement Operating Procedures that can mitigate the effects of GMD events.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going assessments of the potential impact of benchmark GMD events on their respective system as directed in
order 779. The Second Stage GMD Reliability Standards must identify benchmark GMD events that specify what severity GMD events applicable registered entities must assess for potential impacts on the
Bulk-Power System. If the assessments identify potential impacts from benchmark GMD events, the Reliability Standards will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of a benchmark GMD event. The development of this plan cannot be limited to considering operational procedures or enhanced training
alone, but will, subject to the potential impacts of the benchmark GMD events identified in the assessments, contain strategies for mitigating the potential impact of GMDs based on factors such as the age,
condition, technical specifications, system configuration, or location of specific equipment.
As directed in order 779, stage 1 standards must be filed by January 2014, and stage 2 standards must be filed by January 2015.
Draft
Draft 3
Action
Dates
Results
Stage 1 Standard
Final Ballot
EOP-010-1
Clean | Redline to last posting
Implementation Plan
Clean | Redline to last posting
Summary>>
10/25/13 - 11/04/13
Supporting Materials:
Standard Authorization Request
(closed)
Info>>
White Paper Supporting Network Applicability of EOP-010-1
Clean |Redline to last posting
Vote>>
White Paper Supporting Functioning Entity Applicability of EOP-010-1
Clean |Redline to last posting
Ballot Results>>
Consideration of Comments
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
GMD Task Force Operating Procedures
Waiver Authorized by SC but not Exercised
Violation Risk Factor and Violation Severity Level Justifications
Stage 1 Directives Map
Draft 2
Stage 1 Standard
EOP-010-1
Clean | Redline to last posting
Comment Period
Info>>
Implementation Plan
Clean | Redline to last posting
09/04/13 - 10/21/13
Summary>>
(closed)
Supporting Materials:
Unofficial Comment Form (Word)
Ballot Results>>
Submit Comments>>
Standard Authorization Request
White Paper Supporting Network Applicability of EOP-010-1
White Paper Supporting Functional Entity Applicability of EOP-010-1
Consideration of Comments>>
Additional Ballot and Non-Binding
Poll
Updated Info>>
Non-binding Poll Results>>
10/09/13 - 10/21/03
Info>>
GMD Task Force Operating Procedures
Extended an additional day to
achieve quorum.
Comments Received>>
(closed)
Draft Stage 1 Standard
EOP-010-1
Implementation Plan
Vote>>
Comment Period
Info>>
06/27/13 - 08/13/13
(closed)
Submit Comments>>
Ballot and Non-binding Poll
Info>>
08/02/13 - 08/13/13
Vote>>
(closed)
Summary>>
Standard Authorization Request
Consideration of Comments>>
Supporting Materials:
Unoffical Comment Form (Word)
Ballot Results>>
06/27/13 - 07/26/13
Join Ballot Pool>>
(closed)
GMD Task Force Operating Procedures
Non-binding Poll Results>>
Comments Received>>
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Draft 1
Stage 1 Standard
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
EOP-010-1 — Geomagnetic Disturbance Operations
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
Description of Current Draft
This draft is the first posting of the proposed standard and is being done in conjunction with the
posting of the SAR for this project.
Anticipated Actions
Anticipated Date
30-day Formal Comment Period
June 2013
45-day Formal Comment Period with Parallel Initial Ballot
August 2013
Successive Ballot (if needed)
September 2013
Recirculation ballot
November 2013
BOT adoption
November 2013
Draft 1: Date 6/19/13
Page 1 of 8
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EOP-010-1 — Geomagnetic Disturbance Operations
Effective Dates
The first day of the first calendar quarter that is six months beyond the date that this standard is
approved by applicable regulatory authorities. In those jurisdictions where regulatory approval is
not required, the standard shall become effective on the first day of the first calendar quarter that
is six months beyond the date this standard is approved by the NERC Board of Trustees, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
Version History
Version
1
Date
TBD
Action
Project 2013-03
Change
Tracking
N/A
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
Draft 1: Date 6/19/13
Page 2 of 8
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EOP-010-1 — Geomagnetic Disturbance Operations
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Balancing Authority with a Balancing Authority Area that includes any
transformer with high side terminal voltage greater than 200 kV
4.1.3 Transmission Operator with a Transmission Operator Area that includes
any transformer with high side terminal voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to negatively impact the
reliable operation of interconnected transmission systems. 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
protection system Misoperation, the combination of which can lead to voltage collapse
and blackout.
B. Requirements and Measures
R1. Each Reliability Coordinator shall develop, maintain, and implement a GMD Operating
Plan to coordinate GMD Operating Procedures within its Reliability Coordinator
Area. At a minimum, the GMD Operating Plan shall include: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning, Operations Planning]
1.1 A description of activities designed to mitigate the effects of GMD events on the
reliable operation of the interconnected transmission system within the
Reliability Coordinator Area.
1.2 A process for the Reliability Coordinator to determine that the GMD Operating
Procedures of all Transmission Operators and Balancing Authorities in the
Reliability Coordinator Area are coordinated and compatible.
M1. Each Reliability Coordinator shall have a GMD Operating Plan meeting all the
provisions of Requirement R1; and evidence such as a revision history to indicate that
the GMD Operating Plan has been maintained; and evidence to show that the plan was
implemented such as correspondence with Transmission Operators and Balancing
Authorities.
R2. Each Reliability Coordinator shall review its GMD Operating Plan at least once every
36 calendar months from the last effective date. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning, Operations Planning]
Draft 1: Date 6/19/13
Page 3 of 8
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EOP-010-1 — Geomagnetic Disturbance Operations
M2. Each Reliability Coordinator shall have evidence that it has reviewed its GMD
Operating Plan within the timeframe of Requirement R2 such as a dated review
signature sheet or revision history.
R3. Each Transmission Operator and Balancing Authority shall develop, maintain, and
implement Operating Procedures to mitigate the effects of GMD events on the reliable
operation of its respective system. At a minimum, the Operating Procedures shall
include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning,
Operations Planning]
3.1. The steps or tasks for the acquisition and dissemination of space weather
information to its System Operators.
3.2. The steps or tasks to be employed by System Operators that are coordinated
with its Reliability Coordinator's GMD Operating Plan to mitigate the effects on
the system from GMD events.
3.3
The predetermined trigger conditions for initiating and terminating steps or tasks
in the Operating Procedure.
M3. Each Transmission Operator and Balancing Authority shall have GMD Operating
Procedures meeting all the provisions of Requirement R3.
R4. Each Transmission Operator and Balancing Authority shall review its GMD Operating
Procedures at least once every 36 calendar months from the last effective date.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations
Planning]
M4. Each Transmission Operator and Balancing Authority shall have evidence that it has
reviewed its GMD Operating Procedures within the timeframe of Requirement R4 such
as a dated review signature sheet or revision history.
R5. Each Transmission Operator and Balancing Authority shall have a copy of its GMD
Operating Procedures in its primary control room and any applicable backup control
rooms so that it is available to its operating personnel prior to its implementation date.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations
Planning]
M5. Each Transmission Operator and Balancing Authority shall have hard copies or
electronic copies of its GMD Operating Procedure available for inspection as stated.
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 in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Draft 1: Date 6/19/13
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EOP-010-1 — Geomagnetic Disturbance Operations
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 Reliability Coordinator, Transmission Operator and Balancing Authority
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:
The responsible entities shall retain documentation as evidence for 3 years.
If a responsible entity 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 Violation Investigations
Self-Reporting
Complaints Text
1.4. Additional Compliance Information
None
Draft 1: Date 6/19/13
Page 5 of 8
EOP-010-1 — Geomagnetic Disturbance Operations
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning,
Operations
Planning
Medium The Reliability
Coordinator failed to
maintain a GMD
Operating Plan
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan failed
to include one of the
elements listed in
Requirement R1, parts
1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
OR
The Reliability
Coordinator failed to
implement a GMD
Operating Plan within
its Reliability
Coordinator Area
R2
Long-term
Planning,
Operations
Planning
Medium The Reliability
Coordinator reviewed
its GMD Operating
Plan more than 36
months, but less than
39 months, since the
effective date.
The Reliability
Coordinator reviewed
its GMD Operating
Plan more than 39
months, but less than
42 months, since the
effective date.
The Reliability
Coordinator reviewed
its GMD Operating
Plan more than 42
months since the
effective date.
The Reliability
Coordinator did not
review its GMD
Operating Plan
R3
Long-term
Planning,
Operations
Planning
Medium The responsible entity
failed to maintain
GMD Operating
Procedures
The responsible
entity's GMD
Operating Procedures
failed to include one
element in
Requirement R3, parts
The responsible
entity's GMD
Operating Procedures
failed to include two or
more elements in
Requirement R3, parts
The responsible entity
did not have GMD
Operating Procedures
Draft 1: Date 6/19/13
OR
The responsible entity
Page 6 of 8
EOP-010-1 — Geomagnetic Disturbance Operations
3.1 through 3.3.
3.1 through 3.3.
failed to implement its
GMD Operating
Procedures.
R4
Long-term
Planning,
Operations
Planning
Medium The responsible entity
reviewed its GMD
Operating Procedures
and submitted them for
approval more than 36
months, but less than
39 months, since the
last effective date.
The responsible entity
reviewed its GMD
Operating Procedures
and submitted them for
approval more than 39
months, but less than
42 months, since the
last effective date.
The responsible entity
reviewed its GMD
Operating Procedures
and submitted them for
approval more than 42
months since the last
effective date.
The responsible entity
did not review its
GMD Operating
Procedures and submit
them for approval.
R5
Long-term
Planning,
Operations
Planning
Medium N/A
N/A
N/A
The responsible entity
did not have copies of
its GMD Operating
Procedures in its
primary control room
and all backup control
rooms if applicable.
Draft 1: Date 6/19/13
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EOP-010-1 — Geomagnetic Disturbance Operations
D. Regional Variances
None.
E. Interpretations
None.
Draft 1: Date: 6/19/13
Page 8 of 8
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
Retirements
None
Revisions to Glossary Terms
None
Applicable Entities
Reliability Coordinator
Balancing Authority with a Balancing Authority Area that includes any transformer with high side
terminal voltage greater than 200 kV
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side terminal voltage greater than 200 kV
Conforming Changes to Other Standards
None
Effective Dates
EOP-010-1 shall become effective as follows:
In those jurisdictions where regulatory approval is required:
By the first day of the first calendar quarter, six calendar months following applicable
regulatory approval.
In those jurisdictions where regulatory approval is not required:
By the first day of the first calendar quarter, six calendar months following Board of Trustees
approval.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Authorization Request Form
Standards Authorization Request Form
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
EOP-010-1 Geomagnetic Disturbance Operations
TPL-007-1 Transmission System Planned Performance During
Geomagnetic Disturbances
Date Submitted:
SAR Requester Information
Name:
Kenneth Donohoo, Oncor
Organization:
Chair, Geomagnetic Disturbance Task Force
Telephone:
NA
E-mail:
NA
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.):
To mitigate the risk of instability, uncontrolled separation, and Cascading in the Bulk-Power System 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.
Industry Need (What is the industry problem this request is trying to solve?):
While the impacts of space weather are complex and depend on numerous factors, space weather has
demonstrated the potential to disrupt the operation of the Bulk-Power System. A technical discussion of
the effects of geomagnetic disturbances on the Bulk-Power System and recommended actions for NERC
and the industry is provided in the NERC 2012 GMD Report prepared by the GMD Task Force. During a
GMD event, geomagnetically-induced current (GIC) flow in transformers may cause half-cycle
1
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Authorization Request Form
SAR Information
saturation, which can increase absorption of Reactive Power, generate harmonic currents, and cause
transformer hot spot heating. Harmonic currents may cause protection system Misoperation leading to
the loss of Reactive Power sources. The combination of these effects from GIC can lead to voltage
collapse.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will develop requirements for registered entities to employ strategies that
mitigate risks of instability, uncontrolled separation and Cascading in the Bulk-Power System caused by
GMD in two stages as directed in Order 779:
1. Stage 1 standard(s) will require applicable registered entities to develop and implement
Operating Procedures with predetermined and actionable steps to take prior to and during GMD
events which take into account entity-specific factors that can impact the severity of GMD
events in the local area. The Stage 1 standard(s) may also include associated training
requirements for System Operators or development of training requirements may be deferred to
Stage 2.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going
assessments of the potential impact of benchmark GMD events on their respective system as
directed in Order 779. The Stage 2 standard(s) must identify benchmark GMD events that
specify what severity GMD events applicable registered entities must assess for potential
impacts. If the assessments identify potential impacts from benchmark GMD events, the
Standard(s) will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of benchmark GMD events.
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 standards development project will respond to the directives in FERC Order 779 in the timeframe
required by the Order and draw upon the technical products of the GMD Task Force Phase 2 Project and
other relevant information. The GMD Task Force Phase 2 Project addresses the recommendations in
the 2012 GMD Report and is focused on improving the capabilities of industry to assess GMD risk and
develop appropriate mitigation strategies.
2
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Standards Authorization Request Form
SAR Information
Operating Procedures are the first stage in the Standards project to manage risks associated with GMD
events with accompanying training requirements to be addressed in Stage 1 or 2 as determined by the
Standards Drafting Team. Specifically, the project will require owners and operators of the Bulk-Power
System to develop and implement Operating Procedures and accompanying operator training which
may include:
Procedures for acquiring and disseminating forecasting information and warning messages from
the space weather forecasting community to the System Operators;
Predetermined and actionable steps for System Operators to take prior to and during a GMD
event that are tailored to the registered entity's assessment of entity-specific factors such as
geography, geology, and system topology;
Procedures to notify and coordinate with interconnected registered entities for effective action;
Restoration procedures for applicable elements that may be impacted;
Minimum training requirements for System Operators; and
Criteria for discontinuing the use of Operating Procedures at the conclusion of a GMD event.
The second stage of the project will require applicable registered entities to conduct initial and periodic
assessments of the risk and potential impact of benchmark GMD events to the Bulk-Power System and
develop strategies to mitigate the risk of instability, uncontrolled separation, and Cascading.
The definition of benchmark GMD events will be based on reviewed technical analysis.
Periodic update of the assessments will be required to account for new Facilities and
modifications to existing Facilities. It is expected that assessments will also consider new
information and the use of new or updated tools, including new research on GMDs and the ongoing work of the NERC GMD Task Force.
The Standard(s) will require Planning Coordinators and Reliability Coordinators to review plans
addressing the potential impact of benchmark GMD events in order to provide a wide-area
perspective. The Standard Requirements for plans will be supported by reviewed technical
analysis, with consideration of the directives in FERC Order 779.
When both stages have been completed as required by FERC Order 779, all directives in the Order will
have been addressed.
3
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Standards Authorization Request Form
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.
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.
4
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Standards Authorization Request Form
Reliability Functions
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.
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
Enter
(yes/no)
Yes
Yes
Yes
5
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Standards Authorization Request Form
Reliability and Market Interface Principles
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.
Yes
Related Standards
Standard No.
PER-005-1, R3
Explanation
Training on GMD events and mitigation procedures will be added to this
requirement as a specific element in required operator training unless included in
a separate GMD standard.
Related SARs
SAR ID
Explanation
6
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Standards Authorization Request Form
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
The intent of the project is to develop continent-wide requirements that allow responsible entities to
tailor operational procedures or strategies based on the responsible entity's assessment of entityspecific factors such as geography, geology, and system topology. However, the need for regional
variances will be researched throughout the proposed project and may be supported by analysis
required to develop stage 2 Standard(s).
7
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Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the draft stage 1 EOP-010-1 Standard. The electronic comment form must be completed by
8:00 p.m. ET by Monday, August 12, 2013.
If you have questions please contact Mark Olson via email or by telephone at 404-446-9760.
The project page may be accessed by clicking here.
Background Information
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order No. 779.
This posting is soliciting comment on a draft stage 1 Standard and a Standard Authorization Request (SAR)
addressing stages 1 and 2. The draft Standard is a new EOP Standard to specifically address the stage 1
directives in Order No. 779. Including GMD requirements in an existing EOP Standard is not feasible within
the prescribed filing deadline due to the other relevant directives and 5-year review requirements that
must be considered by the drafting team to revise the existing Standards. This effort to revise older EOP
Standards is being carried out by a 5-year review team.
Question 1 asks for stakeholder comment on applicability of the stage 1 Standards. The draft stage 1
Standard applies to Reliability Coordinators, Balancing Authorities with a Balancing Authority Area that
includes any transformer with high side terminal voltage greater than 200 kV, and Transmission Operators
with a Transmission Operator Area that includes any transformer with high side terminal voltage greater
than 200 kV. While some Generator Operators also have Operating Procedures to mitigate the effects of
GMD, the standards drafting team (SDT) did not support including them in mandatory stage 1 standards
because the actions that would be included in a Generator Operator's procedures would require studies
and monitoring equipment that will not be addressed until stage 2. Applicability was also limited by the
minimum voltage threshold of 200 kV. Experience with modeling geomagnetically-induced currents (GIC)
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
has shown that because the resistances of conductors are much higher in systems below 200 kV, the
affects of GMD on these systems are significantly reduced. Historical evidence of transmission systems
affected by severe solar storms supports this conclusion. The 2012 GMD Report contains additional
information.
Question 2 asks for stakeholder comment on Requirement R1, which requires Reliability Coordinators to
develop, maintain, and implement a GMD Operating Plan. This coordinating role for the RC is based on
the functional model and addresses Order No. 779 directives to consider the coordination of Operating
Procedures across regions by a functional entity with a wide-area view. The defined term "Operating
Plan" provides the RC with latitude to determine specific activities necessary to achieve this goal.
Question 3 asks for stakeholder comment on Requirement R3, which requires Transmission Operators and
Balancing Authorities to develop, maintain, and implement GMD Operating Procedures. The draft
standard is intended to allow entities to develop their own procedures based on entity-specific factors.
Recently the GMD Task Force developed Operating Procedure templates that provide a technical resource
for entities to use in developing procedures. Included in the templates are a number of actions that could
be employed to mitigate the effects of GMD, such as reduction of equipment loading, increasing reactive
reserves, reconfiguration of the system, recalling outages, and Load shedding. The templates also describe
indicators of GMD conditions that could be used as trigger conditions for steps or tasks in an entity's
Operating Procedures.
Question 4 asks for stakeholder comment on Requirements R2, R4, and R5. R2 and R4 require applicable
entities to review their GMD Plans/Operating Procedures every 36-months. This periodicity would ensure
improvements in the scientific understanding of GMDs can be incorporated into Operating Procedures in
a timely manner as directed in Order No. 779. Requirement R5 requires each Transmission Operator and
Balancing Authority to have a copy of its GMD Operating Procedures in its Primary and Back-up Control
Rooms, which is consistent with other EOP Reliability Standards.
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
Unofficial Comment Form
Project 2013-03 GMD | June 2013
2
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Questions (1-5) on Draft 1 of EOP-010-1
1. The SDT is proposing that the draft stage 1 Standard should apply to Reliability Coordinators, Balancing
Authorities with a Balancing Authority Area that includes any transformer with high side terminal voltage
greater than 200 kV, and Transmission Operator with a Transmission Operator Area that includes any
transformer with high side terminal voltage greater than 200 kV. Do you agree that the SDT has correctly
identified the applicable functional entities in the initial draft stage 1 Standard? If you do not agree, or
you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.
Yes
No
Comments:
2. In Requirement R1, the SDT is proposing to require Reliability Coordinators to develop, maintain, and
implement a GMD Operating Plan. This coordinating role for the RC is based on the functional model and
addresses the Order No. 779 directive to consider the coordination of Operating Procedures across
regions by a functional entity with a wide-area view. The defined term "Operating Plan" provides the RC
with latitude to determine specific activities necessary to achieve this goal. Do you agree that the SDT has
correctly addressed this directive? If you do not agree that this requirement addresses the directive, or
you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.
Yes
No
Comments:
3. In Requirement R3, the SDT is proposing to require each applicable Transmission Operator and
Balancing Authority to develop, maintain, and implement GMD Operating Procedures. The draft Standard
is intended to allow each entity to develop its own procedures based on entity-specific factors as directed
in Order No. 779. Do you agree that the SDT has correctly addressed the stage 1 directives in Order No.
779? If you do not agree that this requirement addresses the directive, or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your
comments.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-03 GMD | June 2013
3
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4. In Requirements R2 and R4 the SDT is proposing to require applicable entities to review their GMD
Plans/Operating Procedures every 36-months. This periodicity would ensure improvements in the
scientific understanding of GMDs can be incorporated into Operating Procedures in a timely manner as
directed in Order No. 779. In Requirement R5, the SDT is proposing to require each applicable
Transmission Operator and Balancing Authority to have a copy of its GMD Operating Procedures in its
Primary and Back-up Control Rooms, which is consistent with other EOP reliability standards. Do you
agree that the SDT has correctly addressed the directives in Order No. 779 in a manner that is good for
reliability with these requirements? If you do not agree, or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
5. If you have any other comments on this draft Standard that you haven’t already mentioned above,
please provide them here:
Comments:
Unofficial Comment Form
Project 2013-03 GMD | June 2013
4
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Questions (6-10) on SAR for Project 2013-03
The scope of this project is intended to address FERC directives from Order No. 779,
including:
Within six months of the effective date of Final Rule, NERC submit for approval one or more
Reliability Standards that require owners and operators to develop and implement operational
procedures to mitigate the effects of GMDs.
Within 18-months of the effective date of Final Rule, NERC submit one or more Reliability
Standards that require owners and operators to conduct initial and on-going assessments of the
potential impact of benchmark GMD events.
The Second Stage GMD Reliability Standard must identify what severity GMD events (i.e.,
benchmark GMD events) that responsible entities will have to assess for potential impacts.
If the assessments identify potential impacts from benchmark GMD events, owners and operators
must develop and implement a plan to protect against instability, uncontrolled separation, and
Cascading.
The standards development process should consider tasking Planning Coordinators, or another
functional entity with a wide-area perspective, to coordinate mitigation plans across Regions
under the Second Stage GMD Reliability Standards to ensure consistency and regional
effectiveness.
The Second Stage GMD Reliability Standards should not impose “strict liability” on responsible
entities for failure to ensure the reliable operation of the Bulk-Power System in the face of a GMD
event of unforeseen severity.
6. Do you agree that the SAR, as drafted, provides a scope within which to address the directives in Order
No. 779? If not, please explain.
Yes
No
Comments:
7. The SAR identifies a list of reliability functions that may be assigned responsibility for requirements in
the set of standards addressed by this SAR. Do you agree with the list of proposed applicable functional
entities? If no, please explain.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-03 GMD | June 2013
5
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
8. The intent of the project is to develop continent-wide requirements that allow responsible entities to
tailor operational procedures or strategies based on the responsible entity's assessment of entity-specific
factors such as geography, geology, and system topology. However, the need for regional variances will
be researched throughout the proposed project and may be supported by analysis required to develop
stage 2 Standard(s). Are you aware of any regional variances that will be needed as a result of this
project? If yes, please identify the regional variance in your comments:
Yes
No
Comments:
9. Are you aware of any business practice that will be needed or that will need to be modified as a result
of this project? If yes, please identify the business practice in your comments:
Yes
No
Comments:
10. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here.
Comments:
Unofficial Comment Form
Project 2013-03 GMD | June 2013
6
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Geomagnetic Disturbance
Operating Procedure Template
Transmission Operator
Overview
Operating procedures are the quickest way to put in place actions that can mitigate the adverse effects of
geomagnetically induced currents (GIC) on system reliability. They also have the merit of being relatively
easy to change as new information and understanding concerning this threat becomes available.
Operating procedures need to be easily understood by, and provide clear direction to, operating
personnel. This is especially true since most operators are unlikely to frequently respond to significant
GMD events.
Some actions listed below should only be undertaken if supported by an adequate GIC impact study
and/or if adequate monitoring systems are available. Otherwise they can make matters worse. Those
actions are indicated by the phrase "if supported by studies".
Determining that a geomagnetic disturbance (GMD) is significant enough to warrant the initiation of
special operating procedure(s) depends on the geographical location of the power system/equipment in
question coincident with the location of the GMD measurement and forecast. Amount of advance notice
obviously factor heavily in what specific actions can and should be taken. Note these are recommended
actions; specific actions may vary by system configuration, system design and geographic location of the
entity.
Information and Indications
The following are triggers that could be used to initiate operator action:
• External:
o NOAA Space Weather Prediction Center or other organization issues:
Geomagnetic storm Watch (1-3 day lead time)
Geomagnetic storm Warning (as early as 15-60 minutes before a storm, and
updated as solar storm characteristics change)
Geomagnetic storm Alert (current geomagnetic conditions updated as k-index
thresholds are crossed )
• Internal:
o System-wide:
Reactive power reserves
System voltage/MVAR swings/current harmonics
o Equipment-level:
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
GIC measuring devices
Abnormal temperature rise (hot-spot) and/or sudden significant gassing (where online DGA available) in transformers
System or equipment relay action (e.g., capacitor bank tripping)
Actions Available to the Operator
The following are possible actions for Transmission Operators based on available lead-time:
Long lead-time (1-3 days in advance, storm possible)
1. Increase situational awareness
a. Assess readiness of black start generators and cranking paths
b. Notify field personnel as necessary of the potential need to report to individual substations
for on-site monitoring (if not available via SCADA/EMS)
2. Safe system posturing (only if supported by study; allows equipment such as transformers and
SVCs to tolerate increase reactive/harmonic loading; reduces transformer operating temperature,
allowing additional temperature rise from core saturation; prepares for contingency of possible
loss of transmission capacity)
a. Return outaged equipment to service (especially series capacitors where installed)
b. Delay planned outages
c. Remove shunt reactors
d. Modify protective relay settings based on predetermined harmonic data corresponding to
different levels of GIC (provided by transformer manufacturer).
Day-of-event (hours in advance, storm imminent):
1. Increase situational awareness
a. Monitor reactive reserve
b. Monitor for unusual voltage, MVAR swings, and/or current harmonics
c. Monitor for abnormal temperature rise/noise/dissolved gas in transformers 1
d. Monitor geomagnetically induced current (GIC 2) on banks so-equipped 3
e. Monitor MVAR loss of all EHV transformers as possible
1
Requires proper instrumentation (e.g., fiber to hot-spot). Note there may be unusual heating in a location other than the normal hot-spot
location. Dissolved gas analysis may be available in real-time if the transformer is so-equipped; otherwise, post-event DGA may be
performed.
2
10 amperes per phase GIC is a good starting point for potential impacts on heavily loaded transformers when actual limits are unknown.
Newer transformers may have significantly higher GIC withstand capability if specified at the time of construction. For vulnerable
transformers, the OEM can perform analytical withstand studies to better define a particular design's GIC vs. Time withstand capability
3
Regarding the effects of GIC on transformers, real-time mitigation (after a storm is already in progress) should not be taken based solely on
a single indicator (e.g., increased GIC). At least one additional indicator should be monitored to determine if the transformer is actually being
adversely affected (e.g., increased MVAR loss, abnormal temperature rise, etc)
Operating Procedure Template for Transmission Operators
2
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f. Prepare for unplanned capacitor bank/SVC/HVDC tripping4
g. Prepare for possible false SCADA/EMS indications if telecommunications systems are
disrupted (e.g., over microwave paths)
2. Safe system posturing (only if supported by study)
a. Start off-line generation, synchronous condensers
b. Enter conservative operations with possible reduced transfer limits
c. Ensure series capacitors are in-service (where installed)
Real-time actions (based on results of day-of-event monitoring):
1. Safe system posturing (only if supported by study)
a. Selective load shedding 5
b. Manually start fans/pumps on selected transformers to increase thermal margin (check
that oil temperature is above 50° C as forced oil flow at lower temperatures may cause
static electrification)
2. System reconfiguration (only if supported by study)
a. Remove transformer(s) from service if imminent damage due to overheating (possibly
automatic by relaying)
b. Remove transmission line(s) from service (especially lines most influenced by GMD)
Return to normal operation
This should occur two to four hours after the last observed geomagnetic activity.
Related Documents and Links
2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbance on the Bulk Power
System, dated February 2012
http://www.nerc.com/files/2012GMD.pdf
Industry Advisory: Preparing for Geomagnetic Disturbances, dated May 10, 2011
http://www.nerc.com/fileUploads/File/Events%20Analysis/A-2011-05-10-01_GMD_FINAL.pdf
4
Consideration should be given to replacing protective relaying (as part of planned GIC mitigation projects) to prevent false
tripping of reactive assets due to GIC should be considered. Note that capacitor units have harmonic overload limits that
should be observed (see IEEE Std 18).
5
Giving preference of course to the most critical/sensitive loads (e.g., national security, nuclear fuel storage site, nuclear plant offsite
sources, chemical plants, emergency response centers, hospitals, etc)
Operating Procedure Template for Transmission Operators
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Formal Comment Period: June 27, 2013 – August 12, 2013
Ballot Pools Forming Now: June 27, 2013 – July 26, 2013
Upcoming:
Ballot and Non-Binding Poll: August 2-12, 2013
Now Available
A 45-day formal comment period for EOP-010-1 - Geomagnetic Disturbance Operations
is open through 8 p.m. Eastern on Monday, August 12, 2013. A ballot pool is being formed and the
ballot pool window is open through 8 a.m. Eastern on Friday, July 26, 2013 (please note that ballot
pools close at 8 a.m. Eastern and mark your calendar accordingly).
The EOP-010-1 (Geomagnetic Disturbance Operations) initial draft standard, implementation plan, and
VRFs/VSLs are being developed to meet the directives of FERC Order No. 779 for stage 1 (Operating
Procedures) Standards. In the Order FERC established a January 2014 filing deadline for Stage 1
standards. Stakeholders are encouraged to review the posted material early and provide comments
and recommendations for substantive issues that must be addressed to gain their support, as
opportunities to revise and ballot the standard are limited.
Under the revised Standard Processes Manual approved by FERC on June 26, 2013, the EOP-010-1
initial draft standard and associated implementation plan, VRFs and VSLs are posted for a 45-day
comment period, with ballot pool formation during the first 30 days, a ballot and non-binding poll
during the last 10 days of the 45-day period. The SAR for this project is also posted for comment.
Background information for this project, including a link to the Operating Procedure templates
developed by the GMD Task Force, can be found on the project page.
Instructions for Joining Ballot Pool
Ballots pools are being formed for EOP-010-1 (Geomagnetic Disturbance Operations) and the
associated non-binding polls in this project. Registered Ballot Body members must join the ballot pools
to be eligible to vote in the balloting and submittal of an opinion for the non-binding polls of the
associated VRFs and VSLs. Registered Ballot Body members may join the ballot pools at the following
page: Join Ballot Pool
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
During the pre-ballot window, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for this project are:
Initial Ballot: [email protected]
Non-Binding poll: [email protected]
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, August 12, 2013. Please use
the electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Wendy Muller. An off-line, unofficial copy of the comment forms are posted
on the project page.
Next Steps
A ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and Violation Severity
Levels (VSLs) will be conducted as previously outlined.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
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
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Ballot and Non-Binding Poll Results
Now Available
A ballot for EOP-010-1 - Geomagnetic Disturbance Operations and non-binding poll of the associated
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) concluded at 8 p.m. Eastern on Tuesday,
August 13, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Approval
Non-binding Poll Results
Quorum: 76.32%
Quorum: 75.89%
Approval: 62.74%
Supportive Opinions: 55.45%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if needed,
make revisions to the standard. The standard will then proceed to an additional comment period and ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2013 -03 GMD Initial Ballot
Password
Ballot Period: 8/2/2013 - 8/13/2013
Ballot Type: Initial
Log in
Total # Votes: 303
Register
Total Ballot Pool: 397
Quorum: 76.32 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
62.74 %
Vote:
Ballot Results: The drafting team will review comments received.
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
105
1
37
0.474
41
0.526
0
3
24
10
0.5
5
0.5
0
0
0
0
5
91
1
43
0.614
27
0.386
0
2
19
30
1
11
0.524
10
0.476
0
1
8
89
1
28
0.467
32
0.533
0
11
18
54
1
19
0.487
20
0.513
0
0
15
1
0
0
0
0
0
0
0
1
6
0.3
3
0.3
0
0
0
0
3
3
0.2
2
0.2
0
0
0
0
1
8
0.8
7
0.7
1
0.1
0
0
0
397
6.8
155
4.266
131
2.534
0
17
94
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Ballot
Segment
Organization
Member
1
Ameren Services
Eric Scott
Negative
1
American Electric Power
Paul B Johnson
Negative
1
American Transmission Company, LLC
Andrew Z Pusztai
1
Arizona Public Service Co.
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
Affirmative
1
Austin Energy
James Armke
Negative
1
Avista Utilities
Heather Rosentrater
Negative
1
Balancing Authority of Northern California
Kevin Smith
Negative
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
1
City of Tallahassee
Daniel S Langston
Negative
1
Clark Public Utilities
Jack Stamper
Negative
1
Cleco Power LLC
Danny McDaniel
Negative
1
Colorado Springs Utilities
Paul Morland
Negative
1
Consolidated Edison Co. of New York
1
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
1
El Paso Electric Company
Dennis Malone
1
1
1
1
1
1
1
1
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
1
Idaho Power Company
Molly Devine
1
1
1
International Transmission Company
Holdings Corp
JDRJC Associates
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))
SUPPORTS
THIRD PARTY
COMMENTS (Please see
SMUD's
Comment)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
County Public
Utility District)
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool, Inc)
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Michael Moltane
Jim D Cyrulewski
NERC
Notes
Abstain
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
JEA
Ted Hobson
1
1
KAMO Electric Cooperative
Kansas City Power & Light Co.
Walter Kenyon
Jennifer Flandermeyer
Negative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))
Negative
COMMENT
RECEIVED
1
Lakeland Electric
Larry E Watt
1
1
Lincoln Electric System
Long Island Power Authority
Doug Bantam
Robert Ganley
1
Lower Colorado River Authority
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
Manitoba Hydro
Nazra S Gladu
Negative
1
MEAG Power
Danny Dees
Negative
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
1
1
1
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
1
Nebraska Public Power District
Cole C Brodine
Affirmative
Negative
1
1
Northern Indiana Public Service Co.
Julaine Dyke
Negative
1
NorthWestern Energy
John Canavan
Negative
1
Ohio Valley Electric Corp.
Robert Mattey
Negative
1
Oklahoma Gas and Electric Co.
Terri Pyle
Negative
1
Omaha Public Power District
Doug Peterchuck
Negative
1
Oncor Electric Delivery
Jen Fiegel
Negative
1
1
1
1
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
Edward Bedder
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
1
PacifiCorp
Ryan Millard
Negative
1
Platte River Power Authority
John C. Collins
Negative
1
1
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Colorado Spring
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NERC
Standards
Review Forum)
Affirmative
Affirmative
Affirmative
Affirmative
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
1
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP MRONSRF)
Randy MacDonald
Bruce Metruck
Affirmative
Kevin White
David Boguslawski
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Ed Mackowicz)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz American
Electric Power)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (MRO's NSRF)
COMMENT
RECEIVED
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida Power
and Light)
SUPPORTS
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
Portland General Electric Co.
John T Walker
1
1
Potomac Electric Power Co.
PPL Electric Utilities Corp.
David Thorne
Brenda L Truhe
Affirmative
Affirmative
1
Public Service Company of New Mexico
Laurie Williams
Negative
1
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Kenneth D. Brown
1
Puget Sound Energy, Inc.
Denise M Lietz
1
Rochester Gas and Electric Corp.
John C. Allen
1
Sacramento Municipal Utility District
Tim Kelley
1
1
1
Salt River Project
San Diego Gas & Electric
SaskPower
Robert Kondziolka
Will Speer
Wayne Guttormson
1
Negative
THIRD PARTY
COMMENTS WECC(WECC
Position Paper) (WECC Position
Paper)
COMMENT
RECEIVED
Affirmative
Dale Dunckel
Negative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
1
Seattle City Light
Pawel Krupa
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
Sierra Pacific Power Co.
Rich Salgo
Negative
1
Snohomish County PUD No. 1
Long T Duong
Negative
1
South Carolina Electric & Gas Co.
Tom Hanzlik
1
South Carolina Public Service Authority
Shawn T Abrams
1
1
Southern California Edison Company
Southern Company Services, Inc.
Steven Mavis
Robert A. Schaffeld
1
Southwest Transmission Cooperative, Inc.
John Shaver
1
1
1
1
1
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Noman Lee Williams
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
1
Transmission Agency of Northern California Bryan Griess
Negative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
Tucson Electric Power Co.
John Tolo
Negative
1
U.S. Bureau of Reclamation
Richard T Jackson
Negative
1
United Illuminating Co.
Jonathan Appelbaum
Negative
1
1
1
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
2
BC Hydro
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm, Public
Utility District
No.1 of
Snohomish
County)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
2
2
2
2
2
2
2
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
3
Ameren Services
Mark Peters
3
3
3
American Public Power Association
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Nathan Mitchell
Chris W Bolick
NICOLE BUCKMAN
3
Avista Corp.
Scott J Kinney
3
3
3
3
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Anaheim Public Utilities Department
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Dennis M Schmidt
3
City of Austin dba Austin Energy
Andrew Gallo
3
City of Bartow, Florida
Matt Culverhouse
3
City of Farmington
Linda R Jacobson
3
3
City of Garland
City of Redding
Ronnie C Hoeinghaus
Bill Hughes
3
City of Tallahassee
Bill R Fowler
3
City Water, Light & Power of Springfield
Roger Powers
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED
Abstain
Negative
3
Cleco Corporation
Michelle A Corley
Negative
3
Colorado Springs Utilities
Charles Morgan
Negative
3
3
3
3
3
3
3
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
John Bee
Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
3
El Paso Electric Company
Tracy Van Slyke
Negative
3
3
Entergy
FirstEnergy Corp.
Joel T Plessinger
Cindy E Stewart
Affirmative
Affirmative
3
Florida Municipal Power Agency
Joe McKinney
3
3
3
3
3
3
3
3
3
3
3
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Ameren
Services)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool, Inc)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs Utilities)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
Lincoln Electric System
Jason Fortik
Affirmative
3
Los Angeles Department of Water & Power
Mike Anctil
Negative
3
3
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Charles A. Freibert
Stephen D Pogue
3
Manitoba Hydro
Greg C. Parent
3
Manitowoc Public Utilities
Thomas E Reed
Affirmative
Affirmative
Negative
3
MEAG Power
Roger Brand
Negative
3
MidAmerican Energy Co.
Thomas C. Mielnik
Negative
3
Mississippi Power
Jeff Franklin
3
Modesto Irrigation District
Jack W Savage
3
3
Muscatine Power & Water
National Grid USA
John S Bos
Brian E Shanahan
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Colorado Spring
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NERC
Standards
Review Forum)
SUPPORTS
THIRD PARTY
COMMENTS (U.S. Bureau of
Reclamation and
Western Area
Power
Administration)
Affirmative
Affirmative
Nebraska Public Power District
Tony Eddleman
3
New York Power Authority
Northeast Missouri Electric Power
Cooperative
David R Rivera
Skyler Wiegmann
Affirmative
3
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Affirmative
Negative
3
Oklahoma Gas and Electric Co.
Donald Hargrove
Negative
3
Omaha Public Power District
Blaine R. Dinwiddie
Negative
3
Orange and Rockland Utilities, Inc.
David Burke
SUPPORTS
THIRD PARTY
COMMENTS (SPP comments
and MRO NSRF
comments.)
SUPPORTS
THIRD PARTY
COMMENTS (Ed Mackowicz)
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
3
Orlando Utilities Commission
Ballard K Mutters
Negative
3
3
3
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Thomas T Lyons
John H Hagen
Dan Zollner
Affirmative
Affirmative
3
Platte River Power Authority
Terry L Baker
Negative
3
PNM Resources
Michael Mertz
Negative
3
3
3
3
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
COMMENT
RECEIVED
Affirmative
3
3
SUPPORTS
THIRD PARTY
COMMENTS (D. Jacoby)
Affirmative
Affirmative
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (SMUD - Joe
Tarantino) (LPPC)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (WECC Staff
comments)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
3
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Eddy Reece
Thomas M Haire
3
Sacramento Municipal Utility District
James Leigh-Kendall
3
Salt River Project
John T. Underhill
Affirmative
3
Santee Cooper
James M Poston
Negative
3
Seattle City Light
Dana Wheelock
Negative
3
3
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
James R Frauen
Jeff L Neas
Affirmative
Affirmative
Affirmative
Negative
3
Snohomish County PUD No. 1
Mark Oens
3
3
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Hubert C Young
Travis Metcalfe
3
Tampa Electric Co.
Ronald L. Donahey
3
3
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
3
3
3
4
4
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Duane S Dahlquist
4
City of Austin dba Austin Energy
Reza Ebrahimian
Negative
4
City of New Smyrna Beach Utilities
Commission
Tim Beyrle
Negative
4
4
4
4
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Negative
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm, Public
Utility District
No.1 of
Snohomish
County)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Frank Gaffney)
Nicholas Zettel
John Allen
Margaret Powell
Affirmative
Tracy Goble
Affirmative
4
Detroit Edison Company
Daniel Herring
Negative
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
4
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
4
Indiana Municipal Power Agency
Jack Alvey
4
4
4
4
4
4
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Christopher Plante
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Dave
Szulczewski)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Frank Gaffney,
Florida Municipal
Power Agency)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
4
Public Utility District No. 1 of Douglas
County
Henry E. LuBean
4
Public Utility District No. 1 of Snohomish
County
John D Martinsen
Negative
4
Sacramento Municipal Utility District
Mike Ramirez
Negative
4
Seattle City Light
Hao Li
Negative
4
4
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
South Mississippi Electric Power Association Steven McElhaney
Tacoma Public Utilities
Keith Morisette
4
Utility Services, Inc.
Brian Evans-Mongeon
4
5
Wisconsin Energy Corp.
AEP Service Corp.
Anthony Jankowski
Brock Ondayko
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
Affirmative
5
Amerenue
Sam Dwyer
Negative
5
Arizona Public Service Co.
Scott Takinen
Negative
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
5
Avista Corp.
Steve Wenke
5
Clement Ma
5
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
5
City of Tallahassee
Karen Webb
Negative
5
City Water, Light & Power of Springfield
Steve Rose
Affirmative
5
SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm, Public
Utility District
No.1 of
Snohomish
County)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Ameren
Services)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))
Affirmative
Mike D Kukla
Francis J. Halpin
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power Management, LLC
Mike D Hirst
5
Colorado Springs Utilities
Kaleb Brimhall
5
5
5
5
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Abstain
Abstain
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool, Inc)
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs Utilities)
Affirmative
Affirmative
Abstain
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
Detroit Edison Company
5
5
5
Dominion Resources, Inc.
Mike Garton
Duke Energy
Dale Q Goodwine
Dynegy Inc.
Dan Roethemeyer
E.ON Climate & Renewables North America,
Dana Showalter
LLC
5
Alexander Eizans
Negative
Affirmative
Affirmative
Abstain
5
El Paso Electric Company
Gustavo Estrada
5
5
5
5
5
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions
John R Cashin
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner
5
Florida Municipal Power Agency
David Schumann
Negative
5
5
Great River Energy
Hydro-Québec Production
Preston L Walsh
Roger Dufresne
Affirmative
Abstain
5
JEA
John J Babik
Negative
5
Kansas City Power & Light Co.
Brett Holland
Affirmative
Negative
Affirmative
Kissimmee Utility Authority
Mike Blough
Negative
5
Lakeland Electric
James M Howard
Negative
5
5
Liberty Electric Power LLC
Lincoln Electric System
Daniel Duff
Dennis Florom
Affirmative
5
Los Angeles Department of Water & Power
Kenneth Silver
Negative
5
Lower Colorado River Authority
Karin Schweitzer
5
Luminant Generation Company LLC
Rick Terrill
Negative
5
Manitoba Hydro
S N Fernando
Negative
5
Massachusetts Municipal Wholesale Electric
Company
David Gordon
Affirmative
5
MEAG Power
Steven Grego
Negative
5
MidAmerican Energy Co.
Neil D Hammer
Negative
5
Muscatine Power & Water
Mike Avesing
Nebraska Public Power District
Don Schmit
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))
SUPPORTS
THIRD PARTY
COMMENTS (LDWP)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs Utilities)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NERC
Standards
Review Forum)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP and MRO)
Affirmative
Affirmative
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
Northern Indiana Public Service Co.
William O. Thompson
Negative
5
Oglethorpe Power Corporation
Bernard Johnson
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SUPPORTS
THIRD PARTY
COMMENTS (Pablo Onate)
Abstain
Affirmative
5
5
THIRD PARTY
COMMENTS (Kathleen Black)
SUPPORTS
THIRD PARTY
COMMENTS (ACES and SERC
OC)
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
Oklahoma Gas and Electric Co.
Leo Staples
Negative
5
Omaha Public Power District
Mahmood Z. Safi
Negative
5
5
Ontario Power Generation Inc.
Orlando Utilities Commission
David Ramkalawan
Richard K Kinas
5
PacifiCorp
Bonnie Marino-Blair
Negative
5
Portland General Electric Co.
Matt E. Jastram
Negative
5
5
5
5
PowerSouth Energy Cooperative
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Tim Hattaway
Annette M Bannon
Tim Kucey
Steven Grega
5
Puget Sound Energy, Inc.
Lynda Kupfer
Negative
5
Sacramento Municipal Utility District
Susan Gill-Zobitz
Negative
5
Salt River Project
William Alkema
5
Santee Cooper
Lewis P Pierce
Negative
5
Seattle City Light
Michael J. Haynes
Negative
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
5
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Michiko Sell
5
Snohomish County PUD No. 1
Sam Nietfeld
5
5
5
5
5
5
5
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
5
Tri-State G & T Association, Inc.
Mark Stein
5
U.S. Army Corps of Engineers
Melissa Kurtz
5
USDI Bureau of Reclamation
Erika Doot
5
5
5
5
5
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Liam Noailles
6
AEP Marketing
Edward P. Cox
6
6
Alabama Electric Coop. Inc.
Ameren Energy Marketing Co.
Ron Graham
Jennifer Richardson
6
APS
Randy A. Young
6
6
Associated Electric Cooperative, Inc.
Bonneville Power Administration
Brian Ackermann
Brenda S. Anderson
6
City of Austin dba Austin Energy
Lisa L Martin
6
City of Redding
Marvin Briggs
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase,
Seattle City
Light)
SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm, Public
Utility District
No.1 of
Snohomish
County)
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
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NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
6
Cleco Power LLC
Robert Hirchak
Negative
6
Colorado Springs Utilities
Shannon Fair
Negative
6
6
6
6
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Affirmative
Affirmative
Affirmative
6
El Paso Electric Company
Luis Rodriguez
Negative
6
FirstEnergy Solutions
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
Negative
6
Florida Municipal Power Pool
Thomas Washburn
Negative
6
6
6
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
6
Lakeland Electric
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
SUPPORTS
THIRD PARTY
COMMENTS (Pablo Onate)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Affirmative
6
Los Angeles Department of Water & Power
Brad Packer
6
Luminant Energy
Brenda Hampton
6
Manitoba Hydro
Blair Mukanik
Negative
6
Modesto Irrigation District
James McFall
Negative
6
6
Muscatine Power & Water
New York Power Authority
John Stolley
Saul Rojas
Affirmative
Affirmative
6
Northern California Power Agency
Steve C Hill
Negative
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
6
NRG Energy, Inc.
Omaha Public Power District
Alan Johnson
Douglas Collins
6
PacifiCorp
Kelly Cumiskey
Negative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
6
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen
6
Sacramento Municipal Utility District
Diane Enderby
Negative
6
Salt River Project
Steven J Hulet
Affirmative
6
Santee Cooper
Michael Brown
Negative
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THIRD PARTY
COMMENTS (Southwest
Power Pool, Inc)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs Utilities)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (LADWP
Regulatory
Group)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (U.S. Bureau of
Reclamation and
Western Area
Power
Administration)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Ryan Millard)
SUPPORTS
THIRD PARTY
COMMENTS (Florida Light &
Power)
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
Negative
COMMENT
RECEIVED
6
Seattle City Light
Dennis Sismaet
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
Snohomish County PUD No. 1
Kenn Backholm
6
Diane J. Barney
Affirmative
10
10
10
10
10
10
10
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alcoa, Inc.
Foundation for Resilient Societies
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
Michigan Public Service Commission
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Donald G Jones
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
10
Western Electricity Coordinating Council
Steven L. Rueckert
Negative
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
9
9
9
Lujuanna Medina
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
Affirmative
Affirmative
David Hathaway
David F Lemmons
Thomas Gianneschi
Roger C Zaklukiewicz
Edward C Stein
Debra R Warner
William R Harris
Frederick R Plett
Terry Volkmann
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Donald J Mazuchowski
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e108c0fd-8a21-45e6-8e76-8ba4485414b5[8/15/2013 11:59:02 AM]
COMMENT
RECEIVED
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Formal Comment Period: June 27, 2013 – August 12, 2013
Ballot Pools Forming Now: June 27, 2013 – July 26, 2013
Upcoming:
Ballot and Non-Binding Poll: August 2-12, 2013
Now Available
A 45-day formal comment period for EOP-010-1 - Geomagnetic Disturbance Operations
is open through 8 p.m. Eastern on Monday, August 12, 2013. A ballot pool is being formed and the
ballot pool window is open through 8 a.m. Eastern on Friday, July 26, 2013 (please note that ballot
pools close at 8 a.m. Eastern and mark your calendar accordingly).
The EOP-010-1 (Geomagnetic Disturbance Operations) initial draft standard, implementation plan, and
VRFs/VSLs are being developed to meet the directives of FERC Order No. 779 for stage 1 (Operating
Procedures) Standards. In the Order FERC established a January 2014 filing deadline for Stage 1
standards. Stakeholders are encouraged to review the posted material early and provide comments
and recommendations for substantive issues that must be addressed to gain their support, as
opportunities to revise and ballot the standard are limited.
Under the revised Standard Processes Manual approved by FERC on June 26, 2013, the EOP-010-1
initial draft standard and associated implementation plan, VRFs and VSLs are posted for a 45-day
comment period, with ballot pool formation during the first 30 days, a ballot and non-binding poll
during the last 10 days of the 45-day period. The SAR for this project is also posted for comment.
Background information for this project, including a link to the Operating Procedure templates
developed by the GMD Task Force, can be found on the project page.
Instructions for Joining Ballot Pool
Ballots pools are being formed for EOP-010-1 (Geomagnetic Disturbance Operations) and the
associated non-binding polls in this project. Registered Ballot Body members must join the ballot pools
to be eligible to vote in the balloting and submittal of an opinion for the non-binding polls of the
associated VRFs and VSLs. Registered Ballot Body members may join the ballot pools at the following
page: Join Ballot Pool
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
During the pre-ballot window, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for this project are:
Initial Ballot: [email protected]
Non-Binding poll: [email protected]
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, August 12, 2013. Please use
the electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Wendy Muller. An off-line, unofficial copy of the comment forms are posted
on the project page.
Next Steps
A ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and Violation Severity
Levels (VSLs) will be conducted as previously outlined.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
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
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual or group. (85 Responses)
Name (53 Responses)
Organization (53 Responses)
Group Name (32 Responses)
Lead Contact (32 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (14 Responses)
Comments (85 Responses)
Question 1 (61 Responses)
Question 1 Comments (71 Responses)
Question 2 (61 Responses)
Question 2 Comments (71 Responses)
Question 3 (59 Responses)
Question 3 Comments (71 Responses)
Question 4 (59 Responses)
Question 4 Comments (71 Responses)
Question 5 (0 Responses)
Question 5 Comments (71 Responses)
Question 6 (46 Responses)
Question 6 Comments (71 Responses)
Question 7 (45 Responses)
Question 7 Comments (71 Responses)
Question 8 (45 Responses)
Question 8 Comments (71 Responses)
Question 9 (41 Responses)
Question 9 Comments (71 Responses)
Question 10 (0 Responses)
Question 10 Comments (71 Responses)
Individual
Paul Rocha
CenterPoint Energy
Yes
CenterPoint Energy agrees in general with the SDT proposal but has an alternative suggestion for the specific roles of the
applicable responsible entities. Please see CenterPoint Energy’s comments regarding Requirement 1 (Question 2).
Yes
CenterPoint Energy agrees in general with proposed Requirement 1 but offers an alternative proposal on specific aspects of
the Requirement. We propose that the SDT modify R1 to read as follows: Each Reliability Coordinator shall develop,
maintain, and implement a GMD Operating Plan consisting of Operating Procedures developed by the Reliability
Coordinator and coordination of GMD Operating Procedures that may be developed by individual Transmission Operators
and Balancing Authorities within its Reliability Coordinator Area. Discussion: We believe it is not necessary, beneficial, or
efficient for each and every applicable Transmission Operator and Balancing Authority to try to develop GMD-related
Operating Procedures and for the Reliability Coordinator to then try to harmonize multiple individual Operating Procedures
in a way that benefits the region as a whole. We believe the most efficient and beneficial approach is for the Reliability
Coordinator to develop an Operating Plan for the region, but allow (not require) individual Transmission Operators and
Balancing Authorities to supplement the Reliability Coordinator’s Operating Plan with individual Transmission Operator or
Balancing Authority Operating Procedures, as along as those individual Operating Procedures, if any, are coordinated by
the Reliability Coordinator. As repeatedly and correctly noted in the FERC Order, GMD assessment and mitigation requires
a wide-area view. We believe some, if not most, individual Transmission Operators and Balancing Authorities will not be in
a good position to reasonably determine what GMD-related operating actions would benefit the reliable operation of the
entire region. Indeed, for some individual Transmission Operators and Balancing Authorities, it is possible and we believe
likely that no action by that individual party is necessary or beneficial for the reliability of the region as a whole. The
Reliability Coordinator has the wide-area view and is in the best position to determine what Operating Procedures would
benefit the region as a whole. However, we also recognize that some individual Transmission Operators or Balancing
Authorities may have already developed and implemented Operating Procedures, or may do so in the future based on
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
specific concerns or vulnerabilities identified at some future time. We believe that it is beneficial to allow (but not require)
individual Transmission Operators and Balancing Authorities to develop individual Operating Procedures based upon that
entity’s detailed knowledge and assessment of its facilities, as long as provision is made for the Reliability Coordinator to
coordinate such discretionary individual procedures that would supplement the regional procedures. If the SDT agrees with
CenterPoint Energy’s proposal, the language of R1.2 would probably need to be modified by changing “…GMD Operating
Procedures of all Transmission Operators and Balancing Authorities…” to “…GMD Operating Procedures of any submitted
Transmission Operators and Balancing Authorities…”. Also, R3 would need to be modified. R4 and R5 would be deleted.
CenterPoint Energy will discuss proposed changes to R3 in response to the next question.
No
See CenterPoint Energy’s response to the previous question. In this question, the SDT states, “The draft Standard is
intended to allow each entity to develop its own procedures…”. There is a difference between allowing each entity to
develop its own procedures and requiring each entity to do so. R3, as proposed, would do the latter. CenterPoint Energy’s
proposed changes to R1 would allow, but not require, an individual entity to develop its own procedures that would
supplement required regional procedures developed by the Reliability Coordinator. If the SDT agrees with CenterPoint
Energy’s proposed change to R1, R3 would be modified to require Transmission Operators and Balancing Authorities to
submit individual Operating Procedures, if any are developed, to the Reliability Coordinator so that the Reliability
Coordinator could ensure coordination that would benefit the region as a whole. CenterPoint Energy also has specific
concerns that R3.1 is unnecessary and unduly prescriptive. On page 24 of the FERC Order, FERC describes NERC’s
concern with reliance upon the most familiar means of characterizing space weather information, the “K-Index”. On Page 30
of the Order, FERC acknowledged NERC’s concern and took no position regarding overreliance on the K-Index to trigger
operational procedures. R3.3 appropriately allows the responsible entity to choose and then document for compliance what
the trigger mechanism would be, which could be space weather information or some other mechanism (GIC monitoring, for
example). If an individual entity concurs with NERC’s view that space weather information is an unreliable means of
triggering Operating Procedures, then that entity should not be required to acquire and disseminate such information.
Proposed language changes to implement CenterPoint Energy’s suggestions are as follows: R3 Each Transmission
Operator and Balancing Authority that chooses to develop, maintain, and implement Operating Procedures to supplement
the Reliability Coordinator’s Operating Plan described in R1 shall submit such supplemental Operating Procedures to the
Reliability Coordinator for review and approval. 3.1 DELETED 3.2 DELETED (addressed by R1.1) 3.3 Moved to
Requirement 1 as R1.3 R4 DELETED (addressed by R2) R5 DELETED
Yes
CenterPoint Energy is hopeful that the SDT will agree with CenterPoint Energy’s suggested changes. With CenterPoint
Energy’s suggested changes, we believe this standard can be reasonably applied throughout North America. If not, we
believe the proposed standard is problematic for regions that have little or no GMD-related risk and ask that the SDT
consider a proposal to exclude such regions from applicability. CenterPoint Energy understands that such a proposal would
be subject to the Commission’s review and approval but the FERC Order is clear that the Commission understands that
there are different risks in different regions and the Commission does not endorse or order a “one-size-fits-all” approach.
CenterPoint Energy believes candidate regions to exclude from these requirements would potentially include ERCOT,
SERC, and FRCC. However, to re-iterate our main point, we believe this standard could be applied to all regions, even
those regions with minimal GMD-related risk, if CenterPoint Energy’s proposed changes are accepted. Even for those
regions that have more GMD-related risk than other regions, CenterPoint Energy believes it is problematic and, at best,
inefficient, for each and every Transmission Operator and Balancing Authority in such regions to attempt to develop
individual Operating Procedures intended to collectively enhance the reliability of the region as a whole.
Yes
Group
MRO NERC Standards Review Forum (NSRF)
Russel Mountjoy
No
Do not agree with the statement "includes any transformer with high side terminal voltage greater than 200kV". This would
include potiential transformers with high side terminal voltage greater than 200 kV. We believe that the effects of GMD on
these devices are significantly reduced because of the high impedance of these systems. Applicability should be changed
to "includes power transformers with the high side terminal voltage greater than 200kV". The change from "any transformer"
to "power transformer" will match the 2012 GMD Report, Chapter 5 - Power Transformers.
No
Suggest changing language in M1 for clarity and also to replace "implemented" with “coordinated”. M1 should read: M1.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Each Reliability Coordinator shall have a GMD Operating Plan meeting all the provisions of Requirement R1; and evidence
such as a revision history to indicate that the GMD Operating Plan has been maintained; and evidence to show that
development and maintenance of the plan was coordinated with Transmission Operators and Balancing Authorities.
Rationale: The use of the word implemented implies that the actionable items within the Operating Plan were executed as
designed to mitigate the effects of a GMD event. This is an “event driven” measure but the Requirement is to “coordinate”
GMD Operating Plans. By using “coordinate” (vice implement) within the Measure, the measure uses the same words as
the Requirement.
Yes
Yes
Would like clarification of the statement “last effective date” in the Table of Compliance Elements, Rows 2 and 4. Change
the sentence to the following: “The responsible entity reviewed its GMD Operating Procedures and submitted them for
approval more than 36 months, but less than 39 months, since the last effective date of the procedures”
Yes
Yes
No
Yes
MISO has business practice manuals (BPMs) that may require modifications.
If the need for mitigation is identified, it is important to coordinate the response and installation of identified mitigations
between GOs and TOs.
Group
SERC OC Review Group
Stuart Goza
Yes
Yes. We feel that the focus of this standard should be at the higher voltage such as 345 kV lines where line length makes
the lines more vulnerable to GIC. It is recommended that the SDT consider changing the high side terminal voltage to
greater than 300 kV. In addition, if the original language (greater than 200kV), remains in the standard, there should be an
exception for equipment such as transformers.
Yes
Language should be added to ensure coordination between adjacent RCs.
Yes
Yes
Yes
Yes
There is a possibility that the DP would be included because the 200 kV limit may include distribution equipment. The SDT
should consider raising the “bright line” to 300 kV.
The industry is developing the necessary procedures, processes and analysis tools to support the GMD standard. As these
technologies evolve the industry will make modifications to address those changes. SDT should consider and ensure that
entities have adequate time to conduct analyses based on the responsible entity's assessment of entity-specific factors
such as geography, geology, and system topology.
Until analysis is underway there is a possibility that Reliability Emergency Procedures and market operations may require
modification.
Thank you for the opportunity to comment. Disclaimer: The comments expressed herein represent a consensus of the
views of the above named members of the SERC OC Review Group only and should not be construed as the position of
the SERC Reliability Corporation, or its board or its officers.
Individual
John Falsey
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Invenergy LLC
Agree
Individual
Thomas Foltz
American Electric Power
Yes
No
R1, 1.2 We are concerned by requiring the RC to “coordinate” Operating Procedures, and determine their collective
compatibility. Exactly what actions would demonstrate coordination, and how could compliance of it be proven or shown?
The word “coordinate” is very subject to interpretation, and could be inconsistently applied in various audits. R1.2 states that
the GMD Operating Plan shall include “A process for the RC to determine that the GMD Operating Procedures … are
coordinated and compatible.” This could potentially result in different coordination requirements in different regions and
consequently, prevent entities who are operating in multiple regions to use consistent procedures within an entity’s service
territory.
Yes
No
Requirements R2 and R4 state that each applicable entity shall review its GMD Operating Plan/Procedures every 36
months from the last *effective* date while Requirement 5 states that the applicable entities shall have a copy of its GMD
Operating Procedures in the control room(s) prior to its *implementation* date. AEP recommends referencing the effective
date only. R5 should be changed to state “…shall have a hard or electronic copy of its GMD Operating Procedures…”
In the VSL matrix, R4 states that “the responsible entity reviewed its GMD Operating Procedures and submitted them for
approval….”. Requirement 4, as stated, does not require approval for the Operating Procedures, therefore the words “and
submitted them for approval” should be deleted from all four VSLs for R4.
Yes
Yes
No
Yes
The SAR indicates that there may be changes to additional standards eventually proposed as a result of Stage 2 project
efforts. There is no mention of any specific modifications or additional requirements related to the sharing of GMD-related
modeling information. A library of GIC models capturing various system conditions will eventually be necessary. There
should be a similar coordinated effort in developing such a GIC model library as the MMWG that develops power flow and
stability models on an annual basis.
AEP is voting negative on this draft, but can foresee voting in the affirmative if the issues and concerns expressed in this
response are addressed in future versions of the draft.
Individual
John Bee
Exelon and its Affiliates
Yes
Yes
Yes
R3.3, font is incorrect – need the entire number to be bold.
No
Exelon believes that performing a review of GMD Plans / Operating Procedures every 36 months is contrary to the
Paragraph 81 criteria whose effort was to remove truly administrative requirements that do not have an impact on electric
grid reliability. We feel tha R2, M2 and R2, M4 should be removed.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual
Nazra Gladu
Manitoba Hydro
Yes
No
(1) R 1.1: This requirement needs clarification. It refers to a GMD Operating Plan requiring “a description of activities
designed to mitigate the effects of GMD events….”. It is not clear whether the “activities” are intended to be performed by
the Reliability Coordinator or refer to the Operating Procedures of the Transmission Operators / Balancing Authorities, or
some other type of activity directed by the Reliability Coordinator, but performed by other entities. FERC Order 779 only
referred to a possible “coordination “ of Operating Procedures and that element is captured separately in R 1.2. (2) R 1.2:
The requirement for “compatibility” of Operating Procedures causes concern and should be deleted. FERC Order 779 ( Par.
38) specified that GMD standards “should allow responsible entities to tailor their operational procedures based on the
responsible entity’s assessment of entity-specific factors, such as geography, geology and system topology. While FERC
also directed NERC to consider the “coordination” of such operational procedures, it did not require the “compatibility” of
such procedures. Manitoba Hydro already has in place operating procedures to respond to GMD events. The role of
Manitoba Hydro’s Reliability Coordinator is to notify Manitoba Hydro of GMD events and disseminate information on present
and forecasted storm levels. This would be appropriately viewed as coordination. However, requiring a Reliability
Coordinator to determine the “compatibility” of several entities’ Operating Procedures goes beyond coordination and begs
the question of what happens if there is a determination that certain Operating Procedures are not compatible. Does the
Reliability Coordinator have the authority to direct an entity to adopt a different procedure? If so, it is not clear how it would
be determined which responsible entity must change its procedures. Most importantly, this requirement erodes the
discretion that was granted to Transmission Operators and Balancing Authorities under Order 779.
(1) Background - for clarity, consider replacing the words “can lead to” with [may result in]. (2) Purpose - for clarity, consider
replacing the purpose section of the standard with the following sentence: “To [ensure plans, operating procedures, and
resources are maintained and available] to mitigate the effects of geomagnetic disturbance (GMD) [emergencies on the
bulk electric system.]” (3) M2 - consider revising the measure as follows: “Each Reliability Coordinator shall have evidence
[showing] that it has reviewed its GMD Operating Plan within the timeframe of Requirement R2. [Acceptable evidence
could] include a dated review signature sheet or revision history.” (4) 3.1, 3.2 and 3.3 - for completeness, start the sentance
with [A listing of the]. (5) M4 - consider revising the measure as follows: “Each Transmission Operator and Balancing
Authority shall have evidence [showing] that it has reviewed its GMD Operating Procedures within the timeframe of
Requirement R4. [Acceptable evidence could include] a dated review signature sheet or revision history.” (6) Table of
Compliance Elements, R2, Low, Medium, High VSL - insert the word [last] before the words “effective date” for consistency
with Requirement R2. (7) Some entities may reduce exports to neighbors as a mitigating strategy. This method, determined
to be the ideal action, based on system studies, may be perceived as potentially impacting neighbouring entities. What level
of coordination would be required or appropriate to permit the curtailment of exports?
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
No
Should only apply to transformers which are part of BES. BES definition is based upon the low side winding voltage of
greater than 100 kV where as this requirement is based upon high side voltage. Thus, this goes beyond BES elements. We
suggest it apply to transformer with low side winding voltage of 200 kV or greater.
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
No
Requirment 3.2 requires coordination with Reliability coordinator’s plan. Thus, there should be a provision that this
requirement is effective only 6 months after the Reliability coordinator’s plan is available.
No
Requirement R5 is unnecessary and should be deleted altogether. This requirement is a process and not a standard and it
is not necessary to have a hard copy when an electronic copy could be readily available. There is no reliability benefit to this
requirement.
Implementation time for BA and TOP should have 6 additional months than the implementation time for Reliability
coordinator. This is to allow coordination wiht Reliability Coordinator’s procedures affecting BA and TOP. Requirement R1,
1.2 should have the word “all” deleted. It does not serve any specific purpose and could become unnecessarily
burdensome.
No
No
Group
Salt River Project
Bob Steiger
Yes
We agree that the scope is appropriate.
No
We believe that the requirement should state that the Reliability Coordinator should establish triggers that are appropriate
for the given geographical and system exposure for each TO or BA. We would suggest language such as the following:
R1.1 The Reliability Coordinator shall create a preliminary assessment of the exposure for each BA and TO. The plan and
procedures developed by the Reliability Coordinator shall establish trigger levels for initiating and terminating these plans or
procedures based on the preliminary assessment of exposure for each BA or TO.
No
Please see Comment for question 2. The requirements for the Reliability Coordinator should be the same for the
Transmission Operator and Balancing Authority.
Yes
A general comment on the Solar Cycle. It seems that the timing of the peak of the solar cycle might require more frequent
review of plans and procedures.
Yes
Yes
Yes
Yes
Depending on how the Reliability Coordinator writes the plan and procedures there could be an impact to elements of the
BES that are jointly owned, mainly regarding contractual requirements.
We believe the standard needs to address shared elements of the BES. The exposure at one end of a shared element may
be more significant than at the remote end. NERC and the Reliability Coordinator need to provide direction when this type
of situation occurs.
Individual
Joe O'Brien for Ed Mackowicz
NIPSCO
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC reaching levels that would
harm transformers. There is also historical evidence of the presence of and correspondingly the absence of GIC in systems.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
These two factors should be used to determine if a TOP/BA needs to develop, maintain, and implement Operating
Procedures to mitigate the effects of GMD events on the reliable operation of its respective system. If the conditions for GIC
do not exist and there is no history of GIC induced damage or misoperation, a RC should not be required to include those
TOP/BAs in coordinating plans for GMD other than to provide assistance as required in other standards.
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC reaching levels that would
harm transformers. There is also historical evidence of the presence of and correspondingly the absence of GIC in systems.
These two factors should be used to determine if a TOP/BA needs to develop, maintain, and implement Operating
Procedures to mitigate the effects of GMD events on the reliable operation of its respective system. If the conditions for GIC
do not exist and there is no history of GIC induced damage or misoperation, a RC should not be required to include those
TOP/BAs in coordinating plans for GMD other than to provide assistance as required in other standards.
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC reaching levels that would
harm transformers. There is also historical evidence of the presence of and correspondingly the absence of GIC in systems.
These two factors should be used to determine if a TOP needs to develop, maintain, and implement Operating Procedures
to mitigate the effects of GMD events on the reliable operation of its respective system. If the conditions for GIC do not exist
and there is no history of GIC induced damage or misoperation, the TOP should not be required to have plans specifically
for GMD events.
Yes
Yes
Yes
Yes
If the geological conditions and system configuration are such that damaging magintudes of GIC do not exist and there is
no history of GIC induced damage or misoperation in the TOP’s service area, it should not be required to have plans
specifically for GMD events.
No
Individual
Steve Hill
Northern California Power Agency
Yes
For Stage 1 I believe the SDT has it correct; however I am concerned that there is no mention as to what will happen with
IRO-005-3.1a R3 which appplies to a host of registrations. At some point EOP-010-1 will supercede IRO-005-3.1a, but no
mention in the implementation plan is discussed.
No
I think there is too much latitude given. The guidance document describes GMD as more a global issue; not just a regional
issue. I believe the guidance document provides a good list of activities for an RC to start with, but that these activities
should be consistent between various RCs as well as the process the RCs will use to determimne if the TOP and BAs are
coordinated and compatible.
No
In a perfect world this should already exist is folks are truely in compliance with IRO-005-3.1a R3. How are the RCs, TOPs
and Bas curently complying with IRO-005-3a? This might provide some insight for the SDT.
Yes
Yes, but I do not see that this is any different form complying with IRO-005-3 R3 except for the 36 month review cycle.
To suumarize: I will vote no on the initial ballot per comments I have submitted; however that does not mean I am opposed
to this standard. I do believe GMD is an issue that even though it is low frequency can have an reliabiilty impact on the BES
or BPS. I believe the SDT needs to address the IRO-005-3 R3 concern I have discussed. If I were to guess the reason for
EOP-010-1, it would be to replace a pretty loose requirement in IRO-005-3 R3. If this is the case then give more direction
and guidance in the new standard per the guidance document that NERC provided
Yes
I like the SAR; too bad some of the language did not carry over into the implementation plan
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
No
No, but not sure I understand what you are getting at. As stated above geology and soil conditions will vary from region to
region
Yes
Operating procedures that address compliance with IRO-005-3 R3 will need to be modified and new procedure to show
compliance with EOP-010-1 will need to be developed.
No further comments
Individual
Melissa Kurtz
US Army Corps of Engineers
Agree
MRO NSRF
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
Yes
Yes
Yes
Yes
Yes
No
No
If the need for mitigation is identified, ATC believes that it is important to coordinate the response and installation of
identified mitigations between GOs and TOs.
Individual
Jonathan Appelbaum
The United Illuminating Company
Yes
No
Requirements R2 and R4 t to review the plan is purely administrative. As the scientific knowledge evelves R1 and R3
requires a plan to be designed to mitigate the effects of GMD.
Requirement R5 to make the operating plan available in the control center is administrative. Reliability requires the plan to
be implemented as described in requirement R1. VRF for R1 and R3 are Medium since an entity failure to implement the
GMD operating plan may lead to cascade. VRF for R2, R4, and R5 should be Low. R2, R4, and R5 are purely
administrative. The entity is required to have Operating Plans that mitigate the effects of GMD a review of the operating
plan is a secondary activity to developing, maintaining, and implementing an operating plan.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
Yes
We agree with the proposed requirement. However, there currently exists a similar requirement in IRC-005-3.1a, R3, which
says: R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing Authorities are aware of GeoMagnetic Disturbance (GMD) forecast information and assist as needed in the development of any required response plans.
With the introduction of the EOP-010 standard, specifically Requirement R3, the TOP and BA will have operating procedure
in place and be required to monitored GMD activities on an ongoing basis. We question the need to keep R3 of IRO-0053.1a. If the latter is deemed redundant after the adoption of the EOP-010 standard, we suggest the SDT to propose retiring
R3 of IRO-005-3.1a.
Yes
Requirements R2 and R4 could easily be combined. Is there a specific reason why the Reliability Coordinator is separated
from the Transmittion Operator and the Balancing Authority? The wording in these two requirements is identical.
1. Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain and implement
operations plan to mitigate GMD effects. Whether or not there is a hard copy, or electronic copy for that matter, in the
control room and/or the backup control centre is unimportant and irrelevant. In order that the Responsible Entities
implement the plan to comply with the standard requirements, operating personnel needs to be provided and have access
to the plan itself, regardless of where and how it is placed. We suggest removing R5. If Requirement R5 was to be retained,
we suggest adding “Reliability Coordinator” after “Transmission Operator” and “Balancing Authority”. We believe that
Reliability Coordinators should also have a copy of their GMD Operating Procedures in their primary and backup control
rooms. The current Requirement R5 does not include the Reliability Coordinator. 2. The proposed Implementation Plan may
conflict with Ontario regulatory practice with respect to the effective date of the standard. It is suggested that this conflict be
removed by moving the last part in the effective date “,or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.” to the end of the first sentence immediately after “by applicable regulatory authorities”.
The same change should be made to the first bullet under the Effective Dates Section of the Implementation Plan.
No
The Stage II assessment should be done at the interconnection level, not by a patchwork of the Planning Coordinators and
Transmission Planners. If analysis shows there are potential local issues, NERC should consider regional criteria or local
procedures first, rather than an overly complex standard, much of which won’t apply to most entities interonncetion-wide.
Yes
No
No
Group
Pepco Holdings Inc & Affiliates
David Thorne
No
Recommend adding “BES” as qualifier for transformer. 4.1.1 Reliability Coordinator 4.1.2 Balancing Authority with a
Balancing Authority Area that includes any BES transformer with high side terminal voltage greater than 200 kV 4.1.3
Transmission Operator with a Transmission Operator Area that includes any BES transformer with high side terminal
voltage greater than 200 kV
Yes
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
No
Requirement R5 seems administrative in nature (similar to other Paragraph 81 requirements) and seems duplicative of R3
which already requires implementation of the Operating Procedures (i.e. implementation could include making operation
personnel aware of the Operating Procedure and having available). If a separate training requirement is developed, R5
would be further redundant. Recommend that R5 be removed. Requirement R2 and R4 require applicable entities to review
their GMD Plans/Operating Procedures every 36-months. With solar cycles having an average duration of about 11 years
and the Plan and Operating Procedure being potentially utilized 1-2 years during the peak years of the 11 year cycle, how
was the 36 month review criteria reached? Recommend changing to a 48 month review period which still allows for 2-3
reviews during a 11 year solar cycle.
Yes
Suggest that any associated training requirements for System Operators be deferred to Stage 2. Based on what is learned
from Stage 2 benchmark events, may want to revisited functional applicability of Stage 1 (i.e. EOP-010).
Yes
No
No
Individual
Anthony Jablonski
ReliabilityFirst
Yes
There may be cases in which a transformer with a high side terminal voltage of greater than 200 kV is not considered BES
(e.g., the transformer is excluded as part of a local network). ReliabilityFirst requests clarification whether this non-BES
transformer is included within the scope of the standard?
Yes
Yes
Yes
1)Requirement R2 - ReliabilityFirst recommends clarifying the term “effective date” by including the following language “of
its GMD Operating Plan” at the end of the requirement. ReliabilityFirst suggests the following for the SDTs consideration:
"Each Reliability Coordinator shall review its GMD Operating Plan at least once every 36 calendar months from the last
effective date [of its GMD Operating Plan]." 2) Requirement R4 - ReliabilityFirst recommends clarifying the term “effective
date” by including the following language “of its GMD Operating Plan.” ReliabilityFirst suggests the following for the SDTs
consideration: "Each Transmission Operator and Balancing Authority shall review its GMD Operating Procedures at least
once every 36 calendar months from the last effective date [of its GMD Operating Procedures]."
1) Requirement R5 - To be consistent with the language in the other requirements within the standard, ReliabilityFirst
recommends changing the term “implementation date” to “effective date.” ReliabilityFirst offers the following for the SDTs
consideration: "Each Transmission Operator and Balancing Authority shall have a copy of its GMD Operating Procedures in
its primary control room and any applicable backup control rooms so that it is available to its operating personnel prior to its
[effective] date." 2) Consideration for new Requirement R6 - ReliabilityFirst recommends including a new Requirement R6
which would require adjacent Reliability Coordinators to share their respective GMD Operating Plans. During a GMD event,
it can span multiple Reliability Coordinator areas and ReliabilityFirst believes the adjacent Reliability Coordinators should be
aware of each other’s GMD Operating Plans. 3) VSL Requirement R2 - The date ranges between the VSLs are not
inclusive. The VSLs need to reflect "…but less than or equal to…" language. ReliabilityFirst offers the following as an
example “Lower” modified VSL for the SDTs consideration: "The Reliability Coordinator reviewed its GMD Operating Plan
more than 36 months, but less than [or equal to] 39 months, since the effective date." 4) VSL Requirement R4 - The date
ranges between the VSLs are not inclusive. The VSLs need to reflect "…but less than or equal to…" language.
ReliabilityFirst offers the following as an example “Lower” modified VSL for the SDTs consideration: "The responsible entity
reviewed its GMD Operating Procedures and submitted them for approval more than 36 months, but less than [or equal to]
39 months, since the last effective date."
Yes
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
No
Group
Hydro One Networks Inc.
Sasa Maljukan
Yes
Yes
Yes
No
Requirement R5 is of a purely administrative nature, not contributing to reliability. Suggest to eliminate. Emphasis and focus
should be in operating personnel training and awareness. If R5 is kept in the standard, request to clarify the meaning of
“prior to its implementation date.” We believe it should be “prior to actions to implement the plan.” As written in could be
misinterpreted as prior to the standard effective date.
There is a GMD related pre-existing requirement in IRO-005-3.1a R3. It seems, given the extensive Operating Plans
proposed in EOP-010-1, that R3 in IRO-005-3.1a can be retired. This should be considered by the GMDTF. The proposed
Implementation Plan may conflict with Ontario regulatory practice with respect to the effective date of the standard. It is
suggested that this conflict be removed by moving the last part in the effective date “,or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.” to the end of the first sentence immediately after
“by applicable regulatory authorities”.The same change should be made to the first bullet under the Effective Dates Section
of the Implementation Plan.
No
Suggest adding PER-005-1, R3 in the Title of Proposed Standards(s) in this SAR. If not, how will the changes made to
PER-005-1 be coordinated in conjunction with this new EOP-010-1 Standard?The disposition of IRO-005-3.1a R3 needs to
be addressed in the SAR as a retirement.
Yes
Yes
The flexibility in the plan design takes into account locational differences, which are geographically and geologically based.
There is no basis for differences due to regional entity boundaries.
Yes
Individual
Martyn Turner
LCRA Transmission Services Corp
No
The standard has not provided a clear reason for starting at 200 kV, which seems arbitrary. Papers on GMD do indicate the
potential risk to transformer’s increases at the higher voltage levels and in particular to single phase wye connected
transformers. Would propose the following: 4.1.3.1 a Transmission Operator Area that includes any BES transformer with
three single phase core windings connected in a "wye" configuration of 300 kV or greater; or 4.1.3.2 a Transmission
Operator Area that includes any BES transformer with at least one "wye" connected winding greater than 400 kV;
Yes
Yes
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
none
no comment
no comment
Yes
The standard and SAR as drafted do not address differences in geography, geology or system topology variances. For
example because of its southern latitude, the ERCOT region is over 10 times less likely to be impacted by a GMD
occurrence than northern regions of the country and 100 times less than regions of Canada. The cost and effort of
prevention measures should be in line with the potential risks.
no comment
no comment
Individual
Michiko Sell
Public Utility District No. 2 of Grant County, WA
Yes
Yes
Yes
Yes
GCPD is concerned about the implementation period being sufficient to allow the RC to develop and implement a GMD
Operating Plan AND afford adequate time to ensure that each TO and BA within its region the ability to develop, maintain
and implement GMD Operating Procedures that are coordinated with the RC's GMD Operating Plan. Six (6) months is not
sufficient time to allow development and coordination within the region.
Group
Dominion
Connie Lowe
Yes
Yes
Yes
No
As R2 and R4 are currently written, they are purely administrative and do nothing to improve or insure reliability. R1
requires the GMD Operating Plan be maintained which infers the need to review on a periodic basis.
Yes
Dominion suggests adding PER-005-1, R3 in the Title of Proposed Standards(s) in this SAR? If not, how will the changes
made to PER-005-1 be coordinated in conjunction with this new EOP-010-1 Standard.
Yes
No
No
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
Agree
SERC OC Review Group
Individual
Ben Li
Ben Li Associates
Yes
Yes
Yes
1. We agree with the proposed requirement. However, there currently exists a similar requirement in IRC-005-3.1a, R3,
which says: R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing Authorities are aware
of Geo-Magnetic Disturbance (GMD) forecast information and assist as needed in the development of any required
response plans. With the introduction of the EOP-010 standard, specifically Requirement R3, the TOP and BA will have
operating procedure in place and be required to monitored GMD activities on an ongoing basis. We question the need to
keep R3 of IRO-005-3.1a. If the latter is deemed redundant after the adoption of the EOP-010 standard, we suggest the
SDT to propose retiring R3 of IRO-005-3.1a. 2. It R3 is to be retained, then it does not mention “applicable” BAs and TOPs,
which it should. Further, a BA or TOP should be able to adopt a template procedure developed by its Reliability
Coordinator. This should be explained in an administrative appendix to the standard.
Yes
1. Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain and implement
operations plan to mitigate GMD effects. Whether or not there is a hard copy, or electronic copy for that matter, in the
control room and/or the backup control centre is unimportant and irrelevant. In order that the Responsible Entities
implement the plan to comply with the standard requirements, operating personnel needs to be provided and have access
to the plan itself, regardless of where and how it is placed. We suggest removing R5. 2. GMDs are an emerging issue.
There is nothing in this standard that enables information sharing and learning. The RC plan and BA/TOP procedures
should include what sensing information is in the field and the general reporting that such information gathering is done
when GIC symptoms are observed. There should also be information collected following major solar events that is
evaluated by the NERC technical committees. This should not be codified in the requirements, but in an administrative
appendix or an activity to be included in events analysis.
No
The Stage II assessment should be done at the interconnection level, not by a patchwork of the Planning Coordinators and
Transmission Planners. If analysis shows there are potential local issues, NERC should consider regional criteria or local
procedures first, rather than an overly complex standard, much of which won’t apply to most entities interconnection-wide.
Yes
No
Yes
There is a possibility that the procedure of one RC could end up causing redispatch or reconfiguration in a TOP or BA area
or another RC area. There is also a need to address the mechanism for cost recovery, particularly when the problem could
be mitigated locally through upgrades. The cost recovery for redispatch and/or upgrades to BES facilities needamong
affected entities.
Individual
Don Schmit
Nebraska Public Power District
Agree
Southwest Power Pool (SPP)
Group
seattle city light
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
paul haase
No
Seattle City Light supports the general concepts presented in the draft Standard and appreciates that the Standard Drafting
Team affords each entity flexibility as to procedures. However, Seattle is concerned about the broad applicability of the
Standard as proposed, and recommends that it only apply to BA and TOPs with Bulk Electric System (BES) transformers
200kV and above (as well as all RCs). This change would make this Standard consistent with other Standards as well as
the BES definition we've worked so hard on the past several years.
Yes
Yes
Yes
Group
Northeast Power Coordinating Council
Guy Zito
Yes
The Applicability and Purpose conflict however. The Purpose says ”To mitigate the effects of geomagnetic disturbances
(GMD) events by implementing operating procedures.” But the Standard’s Purpose is not consistent with the Standard. The
Standard goes into detail about the mitigation plans. Recommend the Purpose be “To establish and implement GMD
mitigation operating procedures”. The effectiveness of these procedures to mitigate the effects of GMD is unknown.
Yes
Yes
No
The review interval specified in R2 and R4 is 36 months. A five year review would be more appropriate given the length of
the solar cycle. As R2 and R4 are currently written, they are purely administrative and do nothing to improve or ensure
reliability. R1 requires the GMD Operating Plan be maintained which infers the need to review on a periodic basis.
Requirement R5 also is administrative, does not contribute to reliability, and can be eliminated. Suggest to eliminate the
wording “All procedures should be at the primary and backup control center as part of normal business”. Emphasis and
focus should be on operating personnel training and awareness. If it is decided to keep R5 in the Standard, request
clarificiation of the meaning of “prior to its implementation date.” It should be “prior to actions to implement the plan.” As
written it could be misinterpreted as prior to the Standard’s effective date.
There is a GMD related pre-existing requirement in IRO-005-3.1a R3. The implementation plan is not clear regarding the
retirement of the requirement. It would seem, given the extensive Operating Plans proposed in EOP-010-1, that R3 in IRO005-3.1a can be retired. This should be considered by the GMDTF. Simpler wording would make the Standard easier to
understand. Every plan will be different depending upon a wide range of factors affecting GMD mitigation; equipment types
and inventory, location, system configuration and topography, latitude, ground characteristics, etc. Suggest the following
simplifying wording changes to Requirement R3: R3. Each Transmission Operator and Balancing Authority shall develop,
maintain, and implement GMD Operating Procedures. At a minimum, the Operating Procedures shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning] 3.1. The steps or tasks for the acquisition
and dissemination of space weather information to its System Operators. 3.2. The steps or tasks to be employed by System
Operators that are coordinated with its Reliability Coordinator's GMD Operating Plan. 3.3 The predetermined trigger
conditions for initiating and terminating steps or tasks in the Operating Procedure. To be consistent with the terminology in
other standards, suggest changing the wording the Applicability Section to: 4.1.2 Balancing Authority with a Balancing
Authority Area that includes transformers with high voltage terminals connected at 200kV and above. 4.1.3 Transmission
Operator with a Transmission Operator Area that includes transformers with high voltage terminals connected at 200kV and
above. The wording of the Purpose should be changed to "To mitigate the risk of instability, uncontrolled separation, and
Cascading in the Bulk-Power System as a result of geomagnetic disturbance (GMD) events by developing, maintaining and
implementing Operating Plans and Operating Procedures." The Purpose as written should state what GMD affects. It also
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
only addresses the implementation of the Operating Procedures but does not address the development and maintenance
aspect, nor does it address the Operating Plans.
No
Suggest adding PER-005-1, R3 in the Title of Proposed Standards(s) in this SAR. If not, how will the changes made to
PER-005-1 be coordinated in conjunction with this new EOP-010-1 Standard? The disposition of IRO-005-3.1a R3 needs to
be addressed in the SAR as a retirement.
Yes
Yes
The flexibility in the plan design takes into account locational differences, which are geographically and geologically based.
There is no basis for differences due to regional entity boundaries.
Yes
Studies, control room practices and monitoring all will be needed. These are business practice changes and have a cost
which should be considered in this Standard’s development. It should be.
The Standard is a reasonable response to the FERC Directives. When EOP-010-1 becomes effective IRO-005-3a
Requirement R3 becomes redundant and should be removed. This information should be added to the "Related Standards"
section of the SAR.
Individual
Silvia Parada Mitchell
NextEra Energy
No
NextEra Energy is pleased with the work the GMD SDT has done in a very quick period of time, with the exception of
adding certain requirements that no longer fit within the paradigm under which Standards are to be drafted. NextEra
suspects that these requirements were added because of the short period of time in which the SDT drafted the Standard,
and, thus, NextEra is hopeful that once highlighted here that the SDT will quickly decide to delete the requirements as they
are inconsistent with current Standard drafting practices. These requirements are inconsistent with both results based and
P81 concepts, given that they are administrative in nature and do little to promote reliability. While some may see these
requirements as good practices, adding them is no longer consistent with Standard drafting practices nor desired by
stakeholders. New Standards are to be clear, high quality, technically sound and results based. Also, these requirements
are similar to those that FERC recently indicated it would approve for retirement in the P81 Notice of Proposed Rulemaking.
Therefore, NextEra requests that these requirements, noted below, be deleted. R2. Each Reliability Coordinator shall
review its GMD Operating Plan at least once every 36 calendar months from the last effective date. R4. Each Transmission
Operator and Balancing Authority shall review its GMD Operating Procedures at least once every 36 calendar months from
the last effective date.
For the same reasons provided in response to question number #4 (P81 -- administrative in nature), NextEra requests that
the following requirement be deleted: R5. Each Transmission Operator and Balancing Authority shall have a copy of its
GMD Operating Procedures in its primary control room and any applicable backup control rooms so that it is available to its
operating personnel prior to its implementation date.
Individual
Sergio Banuelos
Tri-State Generation and Transmission Association, Inc.
No
Tri-State believes that Balancing Authorities should not be included as an applicable entity because there will be
unnecessary duplication or conflict between the BA and the Reliability Coordinator Operating Plans.
No
Tri-State believes that the proposed standard, as written, is too vague and gives the Reliability Coordinator too much
latitude to create plans as only it deems appropriate. It also does not provide for industry review of these plans beforehand.
Requirement R1 appears to be a "fill in the blank" requirement, which FERC does not approve.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
Tri-State agrees that R3 properly addressed FERC Order No. 779, but believes the implementation periods should be
modified. A 6 month implementation period requiring the Reliability Coordinator to develop the Operating Plan and the
Transmission Operator/Balancing Authority to develop the Operating Procedures is not suitable. The Transmission
Operator/Balancing Authority needs time to ensure their procedures are in accordance with the Reliability Coordinator's
Operating Plan so the implementation dates need to be staggered.
Yes
1. Tri-State believes a 6 month implementation period isn't appropriate for this. This implementation period requires the RC
to develop the Operating Plan and the TOP/BA to develop the Operating Procedures at the same time. The TOP/BA needs
time to ensure their procedures are in line with the RC's Operating Plan so the implementation dates need to be staggered.
2. Tri-State also believes Stage 1 and Stage 2 should be reversed. Developing, maintaining, and implementing a plan
without first conducting assessments and determining the risk is illogical. The Operating Plans should be based on the
results shown of the assessments. 3. There is a lack of evidence showing major damage and widespread outages due to a
geomagnetic disturbance. There should be more studies performed before creating a Reliability Standard in order to better
determine the actual necessity of one. 4. Currently, Tri-State believes that a guidance document would be a better solution
to address the risk of potential geomagnetic disturbances. 5. Tri-State believes all non-BES transformers should be
excluded regardless of high side voltage. In addition any transformer with a delta primary winding should be excluded
regardless of the high side voltage.
Yes
Tri-State believes the SAR provides a scope to address the directives but still strongly believe that Stage 1 and Stage 2
should be in the reverse order. An assessment should be conducted to determine potential impacts from GMD events prior
to developing Operating Procedures to mitigate any possible effects of GMD.
No
Tri-State believes that BAs should not be included as an applicable entity because there will be unnecessary duplication or
conflict between the Balancing Authority and the Reliability Coordinator Operating Plans.
Yes
The assessments from each region will likely provide different results due to the varying geography, geology and location. A
continent-wide standard will not properly or efficiently address the potential risks brought by geomagnetically induced
currents. Tri-State believes that NERC should issue an alert to have the different Regional Entities review and develop
regional standards, guidelines or other criteria to mitigate the possible effects of geomagnetic disturbances rather than
develop a "fill in the blank" standard.
Yes
The NERC IRO-005-3.1a Requirement 3 may need to be retired and incorporated into the new standard(s). The WECC
Geo-Magnetic Disturbance Reporting procedure, which meets the above NERC requirement, may also need to be modified.
It is extremely difficult to determine whether internal business practices will need to be adapted prior to assessments being
performed to identify potential impacts of GMD events. The final GMD Operating Plan(s) developed by the Reliability
Coordinator and Balancing Authorities, which have not been developed, could also impact internal business practices.
Group
Western Area Power Administration
Lloyd A. Linke
Yes
Yes
Western Area Power Administration (WAPA) and the Bureau of Reclamation (Reclamation) believe that R1 should also
require Reliability Coordinators (RCs) to be responsible for monitoring space weather information and alerting TOPs and
BAs. Currently IRO-005-3.1a R3 requires RCs to ensure that TOPs and BAs are aware of GMD forecast information. . This
responsibility should be enhanced in EOP-010-1 R1 and should require RCs to monitor space weather information and alert
TOPs and BAs when GMD watches and warnings begin and end, and to determine what GMD responses are necessary
within the RC footprint. For example, the drafting team could add sub-requirement 1.3 to require, “A process for the
Reliability Coordinator to monitor space weather information and issue alerts to Transmission Operators and Balancing
Authorities when GMD watches and warnings are initiated, and what GMD mitigation actions may be required in response
to the GMD event.”
No
WAPA and Reclamation suggest that the drafting team remove sub-requirement R3.1. WAPA and Reclamation believe it is
inappropriate to place responsibility for acquiring space weather information with the Transmission Operators (TOPs) and
Balancing Authorities (BAs) because BES reliability will not be enhanced when hundreds of individual entities must
determine when a GMD event begins and ends. Neighboring TOPs and BAs would likely react at different times depending
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
on their perception of when a GMD event begins, which could be chaotic and contribute to system instability. As discussed
above in response to Question 1, WAPA and Reclamation believe that responsibility for monitoring space weather,
determining when a watch or warning is appropriate, and alerting TOPs and BAs should be placed at least at the RC level
and possibly with a national coordinating entity. WAPA and Reclamation believe that the drafting team should remove the
current R3.1, and should renumber R3.2 and R3.3 to R3.1 and R3.2. WAPA and Reclamation also suggest that the drafting
team add a new R3.3 to require TOP and BA Operating Procedures to address “The steps or tasks for receiving and
disseminating space weather information to its System Operators.”
Yes
: WAPA and Reclamation also believe Generator Operators should have a role in developing Operating Procedures that will
affect their equipment.
Yes
Yes
Yes
Yes
Individual
Jack Stamper
Clark Public Utilities
Agree
Snohomish County Public Utility District
Group
Western Electricity Coordinating Council
Steve Rueckert
Florida Municipal Power Agency
No
See FMPA concerns on aplicability, type of transformer, and whether or not the BA should be an applicable entity.
Yes
Requirement is acceptable, but implementaiton period is too short
Question applicability of BA and implementation period is too short
Yes
Six Month implementation period is not adequate
Yes
No
I am not aware of any regional variances that would be needed but do have concern about entities in the far south being
subject to these standard prior to studies being conducted.
No
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
No
SNPD agrees in general but believes the 200 kV voltage threshold is premature. In general, we believe that GMD should be
tackled on a regional basis and already by the Reliability Coordinator (“RC”). It is our understanding that location (latitude
and local geology) and the type of systems (i.e., systems with extra-high-voltage, series capacitor compensated lines,
transformer configuration & grounding, and line length) are important elements in a GMD analysis. Therefore, a one-size-
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
fits-all approach based on voltage level would be inappropriate. SNPD believes the Reliability Coordinator (“RC”) would be
in the best position to identify facilities including the appropriate voltage level or other attributes that may become more
apparent as research in this area matures.
Yes
Appropriate implementation time should be given so that the RC has time to develop the GMD operating plan and
coordinate with neighboring RCs as well as other impacted functions. Although GMD and Geomagnetically Induced
Currents (“GIC”) have been well understood for many decades, how they impact various elements of the power grid are still
being assessed by the electric industry and equipment manufactures. Recent work presented at the 2013 IEEE PES
General meeting by Emanuel Bernabeu, Dominion “Overview of GMD Phenomena and ways to study the impact on the
transmission system” and Ramsis Girgis, ABB “Equipment issues transformers, (Major Concern)'s etc. -from the
transformers committee, impacts on transformer fleet and new designs” will provide more insight into appropriate actions to
be taken by the RC and impacted functions. Significant discussion has taken place on this subject in many different forums;
however there is very little credible analysis on how GMD can impact the BES and what level of risk does GMD pose
compared to other adverse impact events. See IEEE Power & Energy article “Geomagnetic Disturbances” by IEEE Power
and Energy Society Technical Council Task Force on Geomagnetic Disturbances, July/August 2013 pg. 71-78.
No
Because GMD can be a wide area event the BA and TOP efforts should focus on coordinating operations and procedures
with the RC. Also GMD is a High-Impact, Low-Frequency event so overall risk to the TOP or BA area should be assessed to
make certain the operations and procedures are commensurate with the risk to reliable operation of the Bulk Electric
System.
Yes
Yes
Yes
No
No
Individual
Rich Salgo
NV Energy
No
The preparation and execution of operating procedures to mitigate the effects of GMD events on the power system are
specific to the Reliability Coordinator and the Transmission Operator entities. We do not believe that actions are required of
the Balancing Authority function at all, as this is not a balancing issue, but rather a transmission operations issue.
Additionally, we believe the scope of applicability should not reach into distribution transformers, particularly radial
transformers serving distribution load. Hence, we recommend that the Applicability section be modified to remove 4.1.2
(Balancing Authority) and place a limitation on 4.1.3 to restrict applicability to BES transformers of the indicated voltage
range.
No
Requiring the RC to develop and maintain a plan is an appropriate requirement; however, it is unclear what the RC must do
under 1.2 to "determine" that the GMD Operating Procedures in its area are coordinated and compatible. Suggest a
language change to "A process for the RC to review and coordinate the GMD Operating Procedures of all TOP's in the RC
Area."
No
OK, except "Balancing Authority" should be removed from R3.
Yes
Agree with the 36 month cycle of review; however, BA should be removed from R4.
No
No, as discussed in response to Q1, the BA should have no direct functional responsibility for the mitigation of GMD. This
should be up to the TOP's within the BA footprint. Inclusion of the BA complicates the situation.
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No
No
Individual
Jen Fiegel
Oncor Electric Delivery Complany LLC
No
The draft fails to include Generator Owners and Generator Operators that have step-up and auxillary transformers with a
terminal higher that 200 kV. If GMD causes unintended ground induced currents (GICs) on Transmission Owners’ and
Transmission Operators Transmission Transformers that are important to the grid, then it stands to reason that step-up and
auxillary transformers are at risk as well. Generator Owners transformers have a great impact to the reliability of the system.
Those transformers need to be included in the Standard. Additionally, it would seem imperative to include generator owner
transformers that supply offsite power to nuclear generation that are above 200 kV. The Standard must include the GO and
GOP in order to address the FERC Order.
No
The proposed language of R1 assumes all Regions operate the same therefore in order to support the structure of Regions
across the North American utility industry, Oncor recommends R1 be revisedto: “Each Reliability Coordinator shall
coordinate the development and maintain a GMD Operating Plan with its Balancing Authority, Transmission Owners,
Transmission Operators, Generator Owners, and Generator Operators that coordinate GMD Operating Procedures within
its Reliability Coordinator Area. At a minimum, the GMD Operating Plan shall include:” Oncor believes the RC should
remain responsible for implementing the plan.
Yes
Yes
No
The Standard did not address all owners and operators of equipment associated with the FERC Order directing NERC to
“submit for approval one or more Reliability Standards that require owners and operators to develop and implement
operational procedures to mitigate the effects of GMDs.” The Standard needs to also include Generation Owners and
Operators of step-up transformers and auxillary transformers with at least one terminal at 200 kV or higher.
No
The Standard did not address all owners and operators of equipment associated with the FERC Order directing NERC to
“submit for approval one or more Reliability Standards that require owners and operators to develop and implement
operational procedures to mitigate the effects of GMDs.” The Standard needs to also include Generation Owners and
Operators of step-up transformers and auxillary transformers with at least one terminal at 200 kV or higher.
No
No
Individual
Oliver Burke
Entergy Services, Inc.
Yes
We feel that the focus of this standard should be at the higher voltage such as 345 kV lines where line length makes the
lines more vulnerable to GIC. It is recommended that the SDT consider changing the high side terminal voltage to greater
than 300 kV. One of the reasons for the change is due to the number of transmission to distribution transformers where the
high side voltage is 230 kV. On the other hand, having the 200 kV cutoff has the potential to create confusion for BA. A BA
with no 200 kV transformers may be intertwined with a TOP that does have the issue and likely will be exposed to issues
that the TOP faces.
Yes
Language should be added to ensure coordination between adjacent RCs.
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No
As mentioned in Q1, a BA with no 200 kV transformers may be intertwined with a TOP that does have the issue and likely
will be exposed to issues that the TOP faces and may need to develop, maintain, and implement GMD Operating
Procedures. The SDT should consider changing the high side terminal voltage to greater than 300 kV.
No
R5 is an administrative requirement for which compliance may be unprovable. This requirement (to have a copy of its GMD
Operating Procedures in its Primary and Back-up Control Rooms) is also redundant to PER-005, which requires a Job Task
Analysis for every task performed by System Operators. All administrative requirements should be deleted.
Yes
Yes
DP may need to be included as the 200 kV limit may include distribution equipment. The SDT should consider changing the
high side terminal voltage to greater than 300 kV.
No
SDT should consider and ensure that entities have adequate time to conduct analyses based on the responsible entity's
assessment of entity-specific factors such as geography, geology, and system topology.
Until analysis is underway there is a possibility that Reliability Emergency Procedures and market operations may require
modification.
Group
Tennessee Valley Authority
Dennis Chastain
Agree
SERC OC Review Group
Individual
Dan Inman
Minnkota Power Cooperative, INC.
No
Do not agree with the statement "includes any transformer with high side terminal voltage greater than 200kV". This would
include potiential transformers with high side terminal voltage greater than 200 kV and smaller, high impedance non-BES
transformers serving load. We believe that the effects of GMD on these devices are significantly reduced because of the
high impedance of these systems. Applicability should be changed to "includes power transformers with the high side
terminal voltage greater than 200kV and a base rating of at least XX MVA". The change from "any transformer" to "power
transformer" will match the 2012 GMD Report, Chapter 5 - Power Transformers. The addition of “XX MVA” will limit the
inclusion of small 200+ kV connected transformers. It is unclear as to what that limit should be and the evidence for that
limit is unknown. Alternatively, could make the statement “includes BES power transformers with a high side terminal
voltage greater than 200 kV” but this could exclude large load serving transformers that do have a significant effect in
relation to GMD events.
No
Comment #1) Suggest changing language in M1 for clarity and also to replace "implemented" with “coordinated”. M1 should
read: M1. Each Reliability Coordinator shall have a GMD Operating Plan meeting all the provisions of Requirement R1; and
evidence such as a revision history to indicate that the GMD Operating Plan has been maintained; and evidence to show
that development and maintenance of the plan was coordinated with Transmission Operators and Balancing Authorities.
Rationale: The use of the word implemented implies that the actionable items within the Operating Plan were executed as
designed to mitigate the effects of a GMD event. This is an “event driven” measure but the Requirement is to “coordinate”
GMD Operating Plans. By using “coordinate” (vice implement) within the Measure, the measure uses the same words as
the Requirement. Comment #2) Suggest replacing the word “all” in R1.2 to “applicable”. Rationale: Using the word “all”
could be interpreted such that TO’s and BA’s that have transformers below 200kV could be affected. Replacing “all” with
“applicable” would avoid confusion, and be in alignment with the SDT intent.
Yes
Yes
See NSRF Comments
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
No
Yes
MISO has business practice manuals (BPMs) that may require modifications.
See NSRF's Comments
Individual
Terry Baker
PRPA
Agree
Florida Power & Light
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
During the July 30, 2013 GMD webinar, the response to one question was that the SDT would consider whether the BA
applicability is appropriate. Austin Energy (AE) would encourage the SDT to complete that effort.
Yes
No
Austin Energy (AE) believes that staggered enforcement dates between R1 and R3 are necessary for TOPs and BAs to
develop Operating Procedures “that are coordinated with [their] Reliability Coordinator’s GMD Operating Plan.” The current
implementation plan establishes a single date for all requirements. During the webinar, AE suggested this and the response
was that NERC anticipates that TOPs' Operating Procedures will be developed first so the timing is acceptable. Given the
definitions of Operating Plan and Operating Procedures in the NERC Glossary, AE understands how an Operating Plan can
be built based on a series of underlying Operating Procedures, but if that is the intended order of operation, R3 should not
require that Operating Procedures be coordinated with the RC’s Operating Plan.
Yes
Overall, AE has voted negative because there is an abundance of cleanup work necessary. AE asks the SDT to consider
the comments above as well as the following points: (1) The SDT should more carefully consider the wording for the
applicability of transformers. During the webinar, someone asked if the intent was to cover only BES tranformers and Mark
Olsen answered in the affirmative. As written, the BES definition considers the low-side voltage (greater than or equal to
100 kV), whereas the Applicability section of EOP-010-1 considers only the high-side voltage. There could be transformers
that are 69/230 kV that would not be BES Elements but would bring in a TOP or BA given the way 4.1.2 and 4.1.3 are
currently written. Additionally, the SDT should consider transformers with high and low-side voltages greater than 100kV but
excluded from the BES based on a documented exclusion or exception. (2) Given the requirement to “develop, maintain
and implement” in R1 and R3, the SDT should consider adding in the same day operations time horizon to cover the
"implement" action. (3) The SDT should clarify what is intended by “implement” in R1 and R3. During the webinar, the
response to this question was unclear. SDTs on other recent projects (COM-003-1, for example) have gone to great lengths
to define what is meant by "implement." RSAWs often state it means to include in your company’s body of operating
procedures. Without explanation, a CEA might interpret implement as follow your Plan/Procedure exactly as written. The
industry needs to know the SDT’s intent. (4) Change the word “all” to “applicable” before the phrase “Transmission
Operators and Balancing Authorities” in R1 part 1.2. (5) The SDT should move the requirement regarding space weather
(currently R3 part 3.1) to R1 so the RC can, in its coordination role, ensure that input data is consistent and applicable to its
Region.
Yes
Yes
No
Not at this time. We believe, however, that due to geographic differences, entities in the ERCOT Region may request
regional variances after we begin developing our approach to GMD.
No
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Group
Oklahoma Gas & Electric
Terri Pyle
No
This standard should not be applicable to Balancing Authorities. FERC Order No. 779 directed the ERO to develop one or
more Reliability Standards that require owners and operators of the BPS to develop and implement operational procedures
to mitigate the effects of GMDs. The functions of the BA center around balancing load and generation and implementing
and accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES elements such as
transformers.
Yes
No
This standard should not be applicable to the Balancing Authorities. FERC Order No. 779 directed the ERO to develop one
or more Reliability Standards that require owners and operators of the BPS to develop and implement operational
procedures to mitigate the effects of GMDs. The functions of the BA center around balancing load and generation and
implementing and accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES elements
such as transformers.
Yes
We agree with the language of these three requirements, however, we believe that the Violation Risk Factor should be
LOWER, not Medium for these documentation related requirements.
While we understand the good intentions of FERC in Order No. 779, we feel that industry’s time would be better spent
pursuing Reliability initiatives that were focused on more pressing, well-documented threats to reliability, particularly as it
relates to entities that are located in more southerly regions of the continent.
No
This SAR should not be applicable to Balancing Authorities. FERC Order No. 779 directed the ERO to develop one or more
Reliability Standards that require owners and operators of the BPS to develop and implement operational procedures to
mitigate the effects of GMDs. The functions of the BA center around balancing load and generation; and implementing and
accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES elements such as
transformers.
No
This SAR should not be applicable to Balancing Authorities. FERC Order No. 779 directed the ERO to develop one or more
Reliability Standards that require owners and operators of the BPS to develop and implement operational procedures to
mitigate the effects of GMDs. The functions of the BA center around balancing load and generation; and implementing and
accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES elements such as
transformers.
No
No
While we understand the good intentions of FERC in Order No. 779, we feel that industry’s time would be better spent
pursuing Reliability initiatives that were focused on more pressing, well-documented threats to reliability, particularly as it
relates to entities that are located in more southerly regions of the continent.
Individual
Texas Reliability Entity
Texas Reliability Entity
No
We agree with the RC and TOP functions. The SDT may also want to consider adding the GOP function so that large
GSU’s are also monitored under this standard.
No
This wording in R1 and R3 are “fill-in-the-blank” type of requirements that NERC has been trying to move away from. We
understand that Phase 2 of the GMD Standard project will provide additional details and clarification.
No
See comments for #2 above.
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Many new Standards have a Guidelines and Technical Basis section as part of the Standard. Would the SDT consider
creating a Guidelines and Technical Basis section?
Group
Florida Municipal Power Agency
Frank Gaffney
No
FMPA appreciates the efforts of the SDT and, in general, we believe the standard is good. However, we believe the
Applicability of the standard needs improvement; and that is the primary reason we are voting Negative. The ORNL report,
which FMPA believes is already unreasonably pessimistic, made several conclusions that are not reflected in the
applicability that FMPA believes ought to be: 1. The applicability ought to be clear that the standard refers to only BES
transformers and not step-down trasformers to distribution. 2. The winding(s) in question needs to be grounded wye
connected and not delta connected for ground current to flow. The geomagnetically induced current (GIC) is ground current.
Hence, the applicability ought to specify transformers with grounded wye connected winding(s) above a certain threshold
voltage 3. According the the ORNL 319 report (http://web.ornl.gov/sci/ees/etsd/pes/pubs/ferc_Meta-R-319.pdf, Figure 1-17),
3 phase / 3 leg core design transformers are much less likely to saturate and result in MVAR demands about 25% of that of
three single phase transformers. Hence, the applicability for > 200 kV and < 400 kV (i.e., the 230 and 345 kV transformers)
ought to be limited to single phase transformers. 4. The primary concerns for GIC is for voltage collapse or relay
misoperation due to increased MVAR demand of transformers that could potentially result in cascading, and potential
damage to transformers (see SAR description of Industry Need); hence, the applicability should not be to BAs but only RCs
and TOPs (see additional discussion in response to question 3). 5. FMPA also believes that the 200 kV threshold ought to
be raised to 300 kV. Almost all 230 kV transformers are 3 phase / 3 leg core transformers with a much lower probability of
becoming saturated; whereas, according to ORNL, about 15% of 345 kV transformers are single phase transformers
(Figure 1-19). In addition, the resistance ot 230 kV lines is significantly higher than 345 kV lines, which will significantly
reduce GIC (see Figure 1-12 noting that the chart is semi-logarithmic) for lines of similar length (see figure 1-14). This is
largely due to the fact that most 345 kV lines are two conductor bundles for RFI purposes and most 230 kV lines are single
conductor; hence, 230 kV lines are roughly twice the resistance of 345 kV lines for the same length of line. FMPA assumes
that GSU’s owned by the GO and operated by the GOP is intended to be included in the applicability (since the vast
majority of GSU’s are grounded wye connected on the high side), but under the interconnecting TOP’s operating plan.
However, the applicability does not reflect this. If the intent of the SDT is to include these GSUs, then the applicability ought
to be changed accordingly. As such, FMPA suggests the following for applicability: 4.1. Functional Entities: 4.1.1 Reliability
Coordinator 4.1.3 Transmission Operator with a: 4.1.3.1 Transmission Operator Area that includes any BES transformer
with three single phase transformers connected in a grounded wye configuration of 300 kV or greater; or 4.1.3.2
Transmission Operator Area that includes any BES transformer with at least one grounded wye connected winding greater
than 400 kV (either three single phase transformers or a three phase transformer); or 4.1.3.3 Transmission Operator Area
that interconnects with any generator interconnection facilities that include a GSU that meets either criteria 4.1.3.1 or
4.1.3.2
No
Bullet 1.2 puts RC’s in a position of responsibility without authority, or at least implies such. The bullet requires the RC to
“determine” that the plans of the BAs and TOPs are coordinated. What happens if, through that process, the plans are
determined not to be coordinated? Is the RC compliant? What would the RC do to get the plans to be coordinated? Does
the RC have the authority necessary to cause this coordination? FMPA suggests looking at the EOP-006 and EOP-005
construct for guidance. And as stated in response to question 1, the BA should not be an applicable entity.
No
As stated previously, the BA should not be an applicable entity. If transmission switching is required that impacts contraints
which in turn impacts dispatch, then existing procedures such as TLR and procedures regarding ancillary services should
be used. If the RC or TOP needs additional generation to be commited or redispatch to occur, the RC or TOP already has
the authority within the standards to require that additional unit commitment or redispatch.
Yes
Although FMPA agrees with a 3 year period, FMPA would prefer a requirement of once every 3 calendar years as opposed
to 36 months to allow more flexibility in scheduling. Again, the BA should not be an applicable entity.
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
Yes
Florida is not susceptible to high GIC due to latitude and geology. At minimum, the applicability of the stadnrd ought to
change based on geography and geology, e.g., maybe Florida’s applicability is only for > 400 kV or not applicabile at all.
No
Group
Southern Company
Wayne Johnson
Yes
The currently drafted standard does not include GOPs as an applicable entity. Consideration should be made to include
them as an entity for reliability purposes. For example, a GOP may decide to take a unit offline if a K7 is declared, and if so,
the reliability entities would need to know that these units are not available, if needed. In addition, if GOPs are added as
applicable entities, they need to have a requirement to provide their plan to the reliability entities. Although we are
suggesting adding the Generator Operator as an applicable entity, we do suggest that they be allowed to develop their own
GMD Operating Plan or implement the GMD Operating Plan of its Transmission Operator. We also believe, consistent with
our response to Question #7 below, that the standard should not apply to BAs, as the the risks mitigated by requiring them
to have Operating Procedures are things that the TOP monitors and can either take action themselves or instruct the BA to
redispatch generation.
Yes
The SDT should consider creating criteria for the RC to use to ensure plans are coordinated and compatible. For example,
criteria were developed for RCs to use to approve TOP restoration plans in EOP-006-2, R5, which indicates that the
“Reliability Coordinator shall determine whether the Transmission Operator’s restoration plan is coordinated and compatible
with the Reliability Coordinator’s restoration plan and other Transmission Operators’ restoration plans within its Reliability
Coordinator Area.” Similarly, the SDT or a committee designated by the SDT should create criteria for RCs to use to ensure
plans are coordinated and compatible.
Yes
An additional requirement should be added requiring BA/TOPs to send their initial plans and any revisions to the RC for
review, since the RC has responsibility for ensuring plans are coordinated and compatible.
Yes
For R3.1, to address potential confidential data issues, the weather data utilized should be publicly available . We
recommend changing R3.1 as follows: R3.1 The steps or tasks for the acquisition and dissemination of publicly available
space weather information to its System Operators.
Yes
Yes
As stated above in our response to Question #1, we suggest that the BA should not be required to have Operating
Procedures for GMD. The risks mitigated are things that the TOP monitor and can either take action themselves or instruct
the BA to redispatch generation.
No
No, as long as the phase 2 standards are non-prescriptive. EOP-010-1 allows entities to account for regional differences
that exist in their area through the development of their plans. This methodology of accounting for regional differences
through plan development needs to be continued as the phase 2 standards or standard changes are developed.
No
Group
Emprimus LLC and Volkmann Consulting
Terry Volkmann
Yes
For the Stage 1 standard, appropriate inclusion of affected transformers is not as important as it will be in Stage 2. What is
important for the Stage 1 standard to capture in its applicability section the portion of the BES most effected by a GMD and
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the most influential to maintain BES reliability. In capturing RC, BA and TOP with 200kv transformers, the SDT has
captured entities that have influence over the 200kv and above system. For entities the own and operate facilities between
100 and 200kv, their system reliability will be maintained by the RC and any neighboring / over-arching entities that
operation 200kv and above.
No
We agree with the language of develop, maintain and implement a GMD Operating Plan. However, the requirement does
not have any evaluation of whether the Operating Plan was appropriately and effectively implemented for an event. M1
should include a post-event evaluation activity and subsequent documentation of the plan implementation.
No
We agree with the language stated in R3. However, R3 should include the requirement of the TOP to communicate that
they have implemented their Operating Procedures. Likewise the requirement does not have any evaluation of whether the
Operating Procedures were appropriately and effectively implemented for an event. M3 should include a post-event
evaluation activity and subsequent documentation of the plan implementation
Yes
R5 should be applicable to RC also.
Yes
Yes
No
Yes
GIC mitigation systems should be excluded from the SPS definition.
Group
FirstEnergy
Doug Hohlbaugh
Yes
Yes
Yes
No
Requirements R2 & R4 FirstEnergy questions the need for Requirement R2 and R4 which propose an every 3-year review
of GMD operating procedures. This is an administrative task and should not be a reliability requirement subject to
mandatory enforcement. The requirements do not adhere to principles identified by the Par. 81 team and now being applied
across all drafting teams. Par 81 Criteria B1 Administrative which states "The Reliability Standard requirement requires
responsible entities to perform a function that is administrative in nature, does not support reliability and is needlessly
burdensome." Additionally, an upcoming draft revision to the NUC-001 standard is proposing to remove a similar obligation
in NUC-001 (R9.1.3). FERC’s Order 779 did not suggest a need for the responsible entities to periodically update their
GMD Operating Procedures every 3-years. Rather in paragraph 39 the Commission states "While responsible entities will
develop and implement operational procedures, NERC can support their efforts, for example, by identifying and sharing
operational procedures found to be the most effective. NERC should also periodically survey the responsible entities’
operational procedures, offer recommendations based on lessons-learned and new research findings, and re-evaluate
whether modification to the Reliability Standards is warranted." It is our understanding that it’s the ERO’s responsibility to
reconsider whether or not more specific minimum GMD procedure expectations should be codified in the standard at some
future date. This could be done for example during the 5-year review period of the standard and the NERC GMD Task
Force could be tasked with providing the review required of NERC and propose changes to the GMD standard if needed.
Requirements R5 Requirement R5 indicates a need for the Operating Procedures to be located at the primary and back-up
control center facility. The intent of Requirement R5 is already covered in standard EOP-008-1, R2. FirstEnergy
recommends that Requirement R5 be struck as a redundant obligation.
The comments are supported by the following GMD standard ballot body members representing FirstEnergy: Bill Smith,
Segment 1 Transmission Owners; Cindy Stewart, Segment 3 Load Serving Entities; Doug Hohlbaugh, Segment 4
Transmission Dependent Utilities; Ken Dresner, Segment 5 Electric Generators and Kevin Querry, Segment 6 Brokers,
Aggregators, and Marketers.
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Yes
Yes
No
No
Individual
David Jendras
Ameren
We believe GMD is a regional issue and therefore a NERC Standard is not necessary. We believe that studies need to be
completed before considering a new NERC Standard. In addition, an entity cannot develop operating plans and procedures
based on unstudied GMD conditions. After the initial assessments of potential impacts of GMD on BES reliability is
complete, then appropriate (if necessary) plans and procedures can then be developed and if necessary a standard could
then be drafted based on results of the studies.
No
We believe that the scope should include initial assessments of potential impacts of GMD before a standard is drafted.
Individual
Catherine Wesley
PJM Interconnection, L.L.C.
Yes
PJM has also signed onto SERC's comments.
Yes
PJM has also signed onto SERC's comments.
Yes
PJM has signed onto SERC's comments. PJM also signs onto the SRC's response to Question #3.
Yes
PJM has signed onto SERC's comments.
Yes
PJM has signed onto SERC's comments.
Yes
PJM has signed onto SERC's comments.
No
PJM has signed onto SERC's comments.
No
PJM has signed onto SERC's comments.
Individual
Michael Lowman
Duke Energy
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Yes
While Duke Energy agrees in principle with starting at 200kV and above for having a GMD process/procedure, we believe
that 300kV and above would be a more appropriate bright-line. In addition, if the bright-line remains at 200kV and above,
we recommend the SDT should consider an alternative method of including only 200kV and above BES elements. Lastly,
Duke Energy believes that only transformers with wye connected winding(s) should be included because only wye
connected winding(s) are affected by GIC(s).
Yes
Duke Energy believes R1.2 should be changed to “Each Reliability Coordinator shall have an Operating Process to
determine that the GMD Operating Procedures of all Transmission Operators and Balancing Authorities in the Reliability
Coordinator Area are coordinated and compatible.“
Yes
Yes
Duke Energy believes that “Same Day Operations” is a more appropriate time horizon for R1 and R3.
Yes
Yes
Yes
Duke Energy believes that due to regional variances, GMD procedures should vary based on GMD severity levels and kV
thresholds.
Yes
If a TOP’s GMD procedure includes the curtailment of transactions to mitigate a potential GMD event, then the modification
of a TOP(s)/TSP(s) business practices may be required.
Group
PacifiCorp
Ryan Millard
No
Generator Operators are listed as applicable functions within the SAR but are absent from the scope of applicability of EOP010-1. If Generator Operators are not included under the standard they should be removed from the scope of the SAR, as
this creates inherent confusion as to their explicit applicability to the standard. Additionally, PacifiCorp does not support
inclusion of the BA as an applicable functional entity.
No
PacifiCorp supports Florida Municipal Power Agency’s position as it relates to Question 2. R1.2 requires the RC to
"determine" that the plans of the BAs and TOPs are coordinated but it is not clear what happens if, through that process,
the plans are determined not to be coordinated? Is the RC compliant? What would the RC do to get the plans to be
coordinated? Does the RC have the authority necessary to cause this coordination? PacifiCorp supports FMPA’s
suggestion to look at the EOP-006 and EOP-005 construct for guidance.
No
PacifiCorp supports Florida Municipal Power Agency’s position as it relates to Question 3. As stated previously, the BA
should not be an applicable entity. If transmission switching is required that impacts contraints which in turn impacts
dispatch, then existing procedures such as TLR and procedures regarding ancillary services should be used. If the RC or
TOP needs additional generation to be commited or redispatch to occur, the RC or TOP already has the authority to require
that additional unit commitment or redispatch.
No
PacifiCorp affirms that if the intent of a review of an entity’s GMD plans and procedures is to improve the scientific
understanding of GMDs, a more prudent requirement would be a periodicity that is post-operative event based.In the
absence of a GMD event, the 36-month requirement is arbitrary and one that would likely be performed by an entity as a
best business practice.
No
PacifiCorp believes the use of the term “Bulk Power System” confuses the scope of the standard. PacifiCorp recommends
replacing “Bulk Power System” with the term “Bulk Electric System” and adding the caveate that the voltage limitation be set
at 200kv and above.
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No
Please refer to the answer supplied for Question 1.
No
None other than those identified.
Group
Beaches Energy Services
Steve Lancaster
Agree
FMPA
Group
Bureau of Reclamation
Erika Doot
Yes
No
The Bureau of Reclamation (Reclamation) and Western Area Power Administration (WAPA) recommend that R1 should
also require Reliability Coordinators (RCs) to be responsible for monitoring space weather information and alerting TOPs
and BAs. Currently IRO-005-3.1a R3 requires RCs to ensure that TOPs and BAs are aware of GMD forecast information. .
This responsibility should be enhanced in EOP-010-1 R1 and should require RCs to monitor space weather information and
alert TOPs and BAs when GMD watches and warnings begin and end, and to determine what GMD responses are
necessary within the RC footprint. For example, the drafting team could add sub-requirement 1.3 to require, “A process for
the Reliability Coordinator to monitor space weather information and issue alerts to Transmission Operators and Balancing
Authorities when GMD watches and warnings are initiated, and what GMD mitigation actions may be required in response
to the GMD event.”
No
WAPA and Reclamation suggest that the drafting team remove sub-requirement R3.1. WAPA and Reclamation suggest
that it is inappropriate to place responsibility for acquiring space weather information with the Transmission Operators
(TOPs) and Balancing Authorities (BAs) because BES reliability will not be enhanced when hundreds of individual entities
must determine when a GMD event begins and ends. Neighboring TOPs and BAs would likely react at different times
depending on their perception of when a GMD event begins, which could be chaotic and contribute to system instability. As
discussed above in response to Question 1, WAPA and Reclamation believe that responsibility for monitoring space
weather, determining when a watch or warning is appropriate, and alerting TOPs and BAs should be placed at least at the
RC level and possibly with a national coordinating entity. WAPA and Reclamation believe that the drafting team should
remove the current R3.1, and should renumber R3.2 and R3.3 to R3.1 and R3.2 respectively. WAPA and Reclamation also
suggest that the drafting team add a new R3.3 to require TOP and BA Operating Procedures to address “The steps or tasks
for receiving and disseminating space weather information to its System Operators.”
Yes
WAPA and Reclamation also believe that Generator Operators should have a role in developing Operating Procedures that
will affect their equipment.
Yes
Individual
Michael Brytowski
Great River Energy
No
GRE agrees with ACES recommending the drafting team provide technical justification for choosing 200 kV as the
threshold. We ask that the drafting team consider increasing the voltage level on the high side of the transformer to 345 kV,
or in the alternative, provide rationale for setting the limit at 200 kV. GRE agrees with ACES and does not believe that the
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Balancing Authority (BA) should be listed as an applicable entity in the GMD standard. Per the NERC functional model, the
BA is focused on balancing load, interchange and generation and supporting system frequency while the Transmission
Operator (TOP) is focused transmission flows and, in particular, controlling voltages. It would be the TOP or RC that would
identify the need to commit additional generation to mitigate loading on transformers or to increase reactive support.
No
GRE agrees with the MRO NSRF on the suggested language change in M1 for clarity and also to replace "implemented"
with “coordinated”. M1 should read: M1. Each Reliability Coordinator shall have a GMD Operating Plan meeting all the
provisions of Requirement R1; and evidence such as a revision history to indicate that the GMD Operating Plan has been
maintained; and evidence to show that development and maintenance of the plan was coordinated with Transmission
Operators and Balancing Authorities. Rationale: The use of the word implemented implies that the actionable items within
the Operating Plan were executed as designed to mitigate the effects of a GMD event. This is an “event driven” measure
but the Requirement is to “coordinate” GMD Operating Plans. By using “coordinate” (versus implement) within the Measure,
the measure uses the same words as the Requirement. This standard is similar to cold weather preparedness, where there
are geographic differences and increased risks to reliability in particular locations. GMD events should be discussed at a
regional level, technical guidance documents should be issued for utilities in high risk locations, and practical solutions
should be reached at each region.
Yes
Because of the wide-area nature of a GMD event, GRE is suggesting a higher level authority such as the NERC Operating
Committee or a NERC technical committee consider drafting guidelines to provide details in preparing for GMD events that
would include recommendations to entites in areas susceptible to GMD events.
No
With NERC’s Relaibilibity Assurance Initiative (RAI), the P81 initiative and the work performed by the Independent Expert
Review Project, R2 & R4 are administrative in nature and suggest the drafting team remove these two requirements.
Similarly, R5 is also in administrative and is redundant with R3 because R3 has an implementation requirement. Per the
P81 NOPR, CIP-003-3, R4 which required the cyber security policy be available to all personnel with CCA responsibilities,
has been approved to be retired.
GRE agrees with ACES, The Long-term Planning Time Horizon for each requirement should be removed. The Long-Term
Planning Horizon covers a period of one year or longer. An operating procedure or plan will cover the Real-Time Operations
horizon or Operations Planning horizon at best. By NERC Glossary definition, an operating plan, process or procedure will
not cover the Long-Term Planning horizon. An operating procedure lists the specific steps that should be taken by specific
operating positions. An operating process includes steps that may be selected based on “Real-time conditions”. A operating
plan contains operating procedures and processes.
Yes
No
As previously stated in Q1, the Balancing Authority (BA) should not be included in the standard.
Yes
See ACES Comment for question 8.
No
The drafting team needs to consider the impacts to smaller entites. Smaller entities have limited resources especially when
considering hardening transformers against GMD events. A cost benefit analysis should be considered when weighing the
reliability gains versus the costs of hardening the electric system.
GMD events cover a wide area and multiple entities. Planning Coordinators (PC) are the ones that should be conducting
the initial assessments with recommendations to the individual entities. The scope of these studies are much broader than
individual entites.
Individual
Wryan Feil
Northeast Utilities
Yes
I agree with the applicability, however if the definition of BES changes I do not think this standard should apply down to
those with transformers having high sides of 100 kV. The impact of GMDs and the magnitude of GICs is greatly reduced at
these lower voltages and doesn't warrant the additional burden it would impose.
Yes
I agree that the RC should coordinate the plans for the BAs and TOPs in its area. It might be beneficial that there be
coordination at the RRO level so that RC plans are coordinated as well, since GMDs/ GICs do not recognize arbitrary
system borders.
Yes
The language in R3 is adequate.
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Yes
Comments on the Geomagnetic Disturbance Operating Procedure Template: Transmission Operator: Information and
Indications: Triggers: External: Watch, Warning and Alert K index numbers are too low. K-index is known to be an unreliable
predictor of GMD severity, however it makes no sense to activate procedures below K7. Triggers Internal: System-wide/
equipment-level: Parameters mentioned could be abnormal due to other causes. There should be corroborating evidence
cause is GMD before entering procedure. Actions Available to the Operator: Should specify that the actions are not limited
to those listed. Long lead-time: Safe system posturing (only if supported by study): Should specify the level of study. For
example, this should mean a coordinated earth conductivity/ system study across a wide area to ensure that other entities
are not negatively impacted- not just a state estimator study. Remove shunt reactors: some systems auto switch reactors.
These (and capacitors) should be left in auto so that they can respond to voltage swings. Day-of-event: Increase situational
awareness: These require being able to corellate the observed parameters to equipment/ system effect before taking
actions Prepare for unplanned capacitor bank/SVC/HVDC tripping: Should add that multiple installations should be
evaluated as a single contingency. Real-time actions: Safe system posturing (only if supported by study): Selective load
shedding: No guidance is provided as to how this could help in a GMD. Manually start fans/pumps on selected
transformers: Due to the hazard of potential catastrophic failure from static electrification caused when oil temperature is
below 50 C, this section should not be mentioned. System reconfiguration (only if supported by study): Should specify the
level of study. For example, this should mean a coordinated earth conductivity/ system study across a wide area to ensure
that other entities are not negatively impacted- not just a state estimator study. Return to normal operation: Why is any time
limit mentioned at all?
Yes
SAR scope is adequate.
No
I believe that due to the wide geographical impact of GMDs/ GICs the RRO should coordinate plans between their RCs and
perhaps with other RROs.
No
All regional variances should be due to geographical, geological and system design factors and should be covered by
developing earth and system models.
Yes
This project will require the conducting of detailed equipment analyses, and in the longer term regional earth conductivity
and system modelling in order to determine impact of GMD/ GIC on equipment and systems. Monitoring and Indications
Key parameters must be identified for control center monitoring (GIC, reactive reserves, harmonics, MVAR, etc.) and
SCADA displays will have to be designed for operator use . Currently a project is underway to install GIC monitoring on
selected transformers and to track the magnitude of GIC/ harmonics with GMD incidence (via Kp provided by SWPC). The
impact on equipment of deviation from normal of these indications must be known, as well as actions recommended by the
transmission owner. Once this is provided, the displays mentioned above can be designed. Procedure Development Once
displays are developed as discussed above, a procedure will need to be developed to address requirements of EOP-010-1
R3. Currently in New England only the northern LCCs and ISO-NE have GMD procedures. These are of a general nature
and may not be sufficient, but they will serve as a starting point for drafting operating procedures. (This presupposes that
parameters for System Operator monitoring have been identified, provided to the control room, displays developed and the
importance of the readings determined by the Transmission Owner.) The standard requires the RC to coordinate TOP
procedures. This may result in a process similar to that for coordinating system restoration plans. Training Once a new
procedure is developed and displays are created, a task analysis will need to take place to identify required changes to the
company specific Reliability Related Task list and required modifications to the training program.This will involve
development and delivery of additional classroom training and evaluation instruments, development and administering of
Job Performance Measures for newly identified Reliability Related Tasks and development, delivery and evaluation of crew
simulator scenarios.
1.) Training requirements should be added to PER-005. Any required training should be added to the applicable GMD
standard(s) (e.g. EOP-010-1.) 2.) The requirement to have the stage 2 standard done and in effect within 18 months is
reasonable, however there should be adequate time within the resulting standard for entities to conduct the required earth/
system studies and alalyze them. Adequate time is also important due to the need to coordinate mitigation efforts across
areas to ensure other entities are not adversely impacted by your organizations actions.
Individual
Phil Anderson
Idaho Power Company
No
For stage 1, operational procedures make sense for Transmission Operations and not necessarily for Generation
Operations. However, generator step-up transformers (GSUs) with a grounded wye high side can be affected by
geomagnetic induced current (GIC). If the GSU is the property of and/or controlled by a generator operator, transformer
information such as GIC, temperature, dissolved gas and abnormal operation may not be easily monitored by the
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Transmission Operator. Any operational changes made by the Generator Operator will need to be coordinated by the
Transmission Operator but the Transmission Operator may not be aware of GSU status. While System wide GMD operating
procedures do not apply to Generator Operators, equipment level situational awareness and monitoring might. Idaho Power
believes this standard should also apply to Generator Operators. Propose adding Generation Operator with any transformer
with a high side terminal voltage greater than 200 kV to the Applicability Functional Entities Section 4.
Yes
Yes
Agree in General. Propose adding Generator Operator to R3 and M3. The Reliability Coordinator needs to coordinate their
procedures with the Transmission Operator, Balancing Authority and Generator Operator.
Yes
Agree in General. Propose adding Generator Operator to R4, M4, R5 and M5. Many of the other standards are using a five
year review cycle. The review requirement should also include a trigger based on system upgrades or major changes to
system topology.
No
Propose adding Generation Operator with any transformer with a high side terminal voltage greater than 200 kV to the
Applicability Functional Entities.
Group
Puget Sound Energy
Denise Lietz
No
The drafting team should ensure that the voltage level in the applicability statement does not include elements excluded by
the Bulk Electric System definition. Specifically, it appears that the applicability statement would include equipment
excluded from the BES by the language of BES Definition Inclusion I1 ("Transformers with the primary terminal and at least
one secondary terminal operated at 100 kV or higher..."). Also, voltage level is not the only measure of GMD influence on
the BES - there are other factors that the standard should include in its assessment of applicability, including grounding
method, grounding resistivity, core type and transformer (coiled equipment) connections. Leaving these factors out of the
applicability section means that many entities who are unlikely to be affected by a GMD event will be unnecessarily
burdened with drafting procedures that they may never need. In addition, it is not clear why the Balancing Authority is
included as an applicable entity - in general, the actions available to the operators are transmission system specific.
However, if the Balancing Authority is removed as a responsible entity, the drafting team should ensure that generation
interconnection facilities are also assessed for applicability with respect to the interconnected TOP.
No
This requirement imposes a heavy burden on the RC. Understanding that some level of coordination is required, perhaps a
lesser level of coordination will be acceptable, at least until phase 2 of the project is complete. Such coordination could be
modeled after the approach in IRO-010, where the RC would set the specifications for the TOP Operating Plans and the
TOP would be required to comply with those specifications.
Group
ACES Standards Collaborators
Jason Marshall
No
(1) We recommend the drafting team provide technical justification for choosing 200 kV as the threshold. We ask that the
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drafting team consider increasing the voltage level on the high side of the transformer to 345 kV, or in the alternative,
provide rationale for setting the limit at 200 kV. (2) We do not believe the science of how GMDs impact the electric grid is
settled. This is evidenced by multiple reports with significantly varying conclusions. While the FERC order indicated that
most reports agree that there is a minimum risk for voltage collapse due to excessive reactive power consumption of
transformers during extremen GMD events, the reports may not emphasize the geographic risk of the problem. For
example, does a utility in South Florida have the same risk as a utility in northern Maine? If the risks are different, a
requirement for an operating procedure for all entities including the southern most entities is premature at this point. We
understand that NERC has an obligation to respond to the FERC GMD directive and will support them in their efforts,
however, we wonder if NERC should look for an equally efficient and effective alternative. We believe that such an
alternative should include pointing to the existing and proposed standards requirements that require registered entities to
respond to voltage emergencies. (3) Given the unsettled GMD science, we think it is premature to write a standard requiring
specific GMD operating plans and procedures and may cause considerable overlap and redundancy within the standards
which the P81 project was intended to remove and which FERC has already proposed to approve. For example, TOP-0011a R2 and R8 already requires the TOP to take immediate actions to alleviate operating emergencies and to restore
reactive power balance. TOP-002-2.1b R8 requires the TOP to plan to meet voltage and/or reactive limits, including the
deliverability/capability for any single Contingency. TOP-004-2 R6.1 requires the TOP to have policies and procedures for
monitoring and controlling voltage levels and reactive power flows. Finally, EOP-001-2 R2.2 requires the TOP to “develop,
maintain, and implement a set of plans to mitigate operating emergencies on the transmission system”. These standards
requirements are applicable at all times including during GMD events. Thus, the proposed requirements will create an
opportunity for double jeopardy due to the redundancy in the requirements. (4) The Balancing Authority (BA) should not be
listed as an applicable entity in the standard. Per the NERC functional model, the BA is focused on balancing load,
interchange and generation and supporting system frequency while the Transmission Operator (TOP) is focused
transmission flows and, in particular, controlling voltages. The background section is focused on preventing transformer hot
spot heating and voltage collapse through excessive use of reactive power which clearly aligns with the TOP tasks and not
the BA tasks in the NERC functional model. While the BA might have a role if additional generation is committed, the role
would be, in essence, to respond to TOP actions. It would be the TOP that would identify the need to commit additional
generation to mitigate loading on transformers or to increase reactive support. The BA would commit generation in
response to the TOP directions and would utilize existing operating procedures and processes it has for managing
commitment of units. Its existing procedures and processes, for example, might include a minimum generation procedure.
Implementing the procedure in response to excess generation that needs to be committed to respond to a GOP event
would be no different than responding when load has simply decreased below the normal minimum generation limits. Thus,
there is no need to add the BA because its existing procedures and processes would be sufficient to respond to the TOP
actions.
No
(1) Having another duplicative “operating plan” does not improve reliability on the bulk electric system. The reliability
standards already require several types of plans that could be enhanced to address GMD events. While we agree that
flexibility is better than specificity, we disagree with the approach that another plan is required. The drafting team should
consider enhancing existing operating plans and other approaches to respond to the FERC directive. (2) We believe that
NERC should respond to the FERC directive with an equally efficient and effective alternative to developing a new reliability
standard. Since the new standard will be largely redundant with with existing standards requirements, there is technical
justification to support an alternate approach. The alternate approach would include relying on existing standards
requirements. For example, IRO-014-1 R1 requires the RC to have operating procedures, processes or plans for activities
that require notification or exchange of information with other reliability coordinators. Since the electric industry already
takes an “all hazards” approach to planning the operation of the grid, the RCs in geographies with greater risks to GMD
events should be able to rely on existing processes, procedures and plans to coordinate responses to GMD events. The
electric industry’s excellent response to large events such as hurricanes has proven the “all hazards” approach to planning
is effective. (3) A reliability standard is not always the best solution to address a reliability concern. This standard is similar
to cold weather preparedness, where there are geographic differences and increased risks to reliability in particular
locations. We cannot support a standard that attempts to address the issue in broad generalities. GMD events should be
discussed at a regional level, technical guidance documents should be issued for utilities in high risk locations, and practical
solutions should be reached at each region.
No
(1) The proposed standard is responsive to the FERC directive, but it fails to take into account existing reliability standards
that overlap with the proposed draft, and creates duplicative requirements that could result in double jeopardy. For instance,
TOP-004-2 R6.1 requires the TOP to have policies and procedures for monitoring and controlling voltage levels and
reactive power flows. Since the electric industry has always taken an “all hazards” approach to planning and operating the
electric grid, these policies and procedures will have already considered extreme operating situations such as events that
might occur during a GMD event. These policies and procedures would, therefore, be sufficient to respond to a GMD event
without the need to make them specific to the GMD event or without the need to create a duplicative standard. The drafting
team or a NERC technical committee, such as the Operating Committee, could draft a reliability guideline to provide
additional detail of how to prepare for GMD events and make recommendations for utilities in areas susceptible to GMD
events to include preparations in their planning processes.
No
(1) Requirements R2, R4 and R5 meet one or more Paragraph 81 criteria and should not be written as separate
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requirements that will result in a separate violation for failing to conduct the review on a timely basis or failing to have a
copy of the operating plan or procedure in the control centers. A requirement is subject to retirement under P81 if the
requirement fits any of the following criteria: it is administrative in nature, requires data collection/data retention, purely
documentation or reporting, requires periodic updates, concerns only a commercial or business practice, is redundant with
other standards, hinders the protection or reliable operation of the BES, or has little, if any, value as a reliability
requirement. (2) Requirement R5 is very similar to CIP-003-3 R4 which requires the cyber security policy to be available to
all personnel with access to or responsibility for Critical Cyber Assets. In the P81 NOPR, FERC recently proposed to
approve retiring CIP-003-3 R4 because it is administrative and it would be not be practical to implement the cyber security
policy if it was not available to personnel. Similarly, R5 would be redundant with R3 because R3 has an implementation
requirement. How can the TOP or BA implement the operating procedure if it is not available to its operating personnel per
R5? How would an auditor verifying that a copy of the plan in the primary and backup control rooms benefit reliability? It
could be placed in these rooms with no notification to system operators and no training provided to system operators on the
implementation. Obviously, this would not support reliability. Requirements R2 and R4 are similar to the NUC-001-2 R9.13
which compel the Nuclear Plant Generator Operator and Transmission Entity to review their agreement every three years.
FERC also proposed to retire it. Thus, R2 and R4 should be removed. If some vestige R2 and R4 are to remain, they
should be made a sub-part of R1 and R3 so that a separate violation is not recorded for failure to review in the 36 month
time frame. (3) We do agree that the 36-month time frame for review is reasonable.
(1) We are concerned that implementation of an operating procedure for GMD may require the removal a number of
transformers and could be viewed as causing a burden to neighboring systems contrary to TOP-001-1a R7. TOP-001-1a
R7 compels the TOP and GOP to not remove facilities from service if it would burden neighboring systems unless there is
not time for notification and coordination. Could the requirement to write an operating procedure for responding to GMD
events be viewed as allowing time for coordination and notification particularly if the TOP documented in their plan to notify
their RC? If EOP-010 persists, TOP R7.3 should be modified to clarify that a TOP and GOP may not have sufficient time
during an extreme GMD event to make appropriate notifications and the requirement for the RC to have an operating plan
will be viewed as this coordination. (2) The Long-term Planning Time Horizon for each requirement should be removed. The
Long-Term Planning Horizon covers a period of one year or longer. An operating procedure or plan will cover the Real-Time
Operations horizon or Operations Planning horizon at best. By NERC Glossary definition, an operating plan, process or
procedure will not cover the Long-Term Planning horizon. An operating procedure lists the specific steps that should be
taken by specific operating positions. An operating process includes steps that may be selected based on “Real-time
conditions”. A operating plan contains operating procedures and processes. (3) Part 3.1 in R3 is unnecessary because
NERC already designates MISO and WECC RC to monitor the space weather through the National Oceanic and
Atmospheric Administration (NOAA) Space Weather Prediction Center (SWPC). MISO communicates this information to the
Eastern and ERCOT Interconnections through reliability coordinator information system (RCIS) and WECC communicates it
to the Western Interconnection as documented in a NERC alert. There is not a need to codify a process that is already in
place and works effectively.
Yes
While we agree that the SAR does provide a plan to address the FERC directives, we continue to believe new standards
with requirements to write specific operating plans or procedures is premature and that NERC should pursue and equally
effective and efficient alternative. The electric industry is already required to have policies and procedures to manage
emergency conditions through the requirements such as TOP-004-2 R6.1 and EOP-001-2 R2.2. Since the electric industry
has always taken an “all hazards” approach to planning and operating the electric grid, these policies and procedures will
have already considered extreme operating situations such as events that might occur during a GMD event. The electric
industry’s excellent response to large events such as hurricanes, blizzards, and tornadoes has proven the “all hazards”
approach to planning is effective.
No
As stated above in question one, the Balancing Authority (BA) should not be included in the standard. Per the NERC
functional model, the BA is focused on balancing load, interchange and generation and supporting system frequency while
the Transmission Operator (TOP) is focused transmission flows and, in particular, controlling voltages. While the BA might
have role if additional generation is committed, the role would be, in essence, to respond to TOP actions. It would be the
TOP that would identify the need to commit additional generation to mitigate loading on transformers or to increase reactive
support.
Yes
(1) Because the science it unsettled at this point, it is difficult to imagine a situation with a GMD event so severe that it
impacts significantly the furthest southern parts of the U.S. Thus, a regional variance is likely necessary for these areas.
However, until the science is settled it is challenging to know where to draw the line for where the regional variances are
needed geographically or geologically.
Yes
This standard will impact multiple business practices within the industry regarding budgetary issues. The cost of hardening
transformers to withstand severe GMD events does not justify the reliability gains. This is especially true for smaller entities
with limited resources.
The SAR discusses additional training requirements that ultimately will impact system operators. System operators already
have a heavy training load from mandatory training required to meet the PER requirements (i.e. 32 hours of emergency
operations training) to the training requirements to maintain NERC certification (i.e. 200 hours every three years for an RC).
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We would advise the drafting team to be careful to not overburden the system operators with additional training
requirements that could distract them from doing their job of maintaining system reliability.
Group
DTE Electric
Kathleen Black
No
System study of areas potentially affected by GMDs should be identified before standard is written requiring all entities to
have plans and operating procedures.
No
Instead of each RC, TO and BA developing its own plan to mitigate effects of GMDs, the standard should state that each
TO and BA have a plan to support its RC's GMD plan. If individually created, the plans may conflict.
No
Entities with no previous effects from GMDs should be exempted by their RX from developing a plan and entities with
potential problems with GMDs should be required to develop plans to support their RC's plan and provide plan details to
their RC.
No
Please see previous comments from Questions 1, 2, and 3.
Yes
Yes
No
No
Individual
Patricia Metro
National Rural Electric Cooperative Association (NRECA)
No
NRECA recommends increasing the voltage level threshold from 200 kV to 345 kV. The drafting team has not provided a
technical justification for choosing the 200 kV threshold. It appears that from the limited previous experiences associated
with GMD events that there was no substantive impact on equipment at voltages below 345 kV. In addition, it is important
that any standard that is developed addressed regional geographic differences associated with the impacts of GMD in the
requirements of the standard. Present data does not support that the potential for equipment damage resulting in a GMD
event is the same for a cooperative in the Northeast and a cooperative in the Southeast. The inclusion of the Balancing
Authority as an applicable entity is not necessary. If the events being addressed in this standard are solely related to
preventing transformer hot spot heating and voltage collapse through excessive use of reactive power, these types of
events are managed by the Transmission Operator not the Balancing Authority. The Balancing Authority will only provide
generation support as directed by the Transmission Operator.
No
As explained in response to Question 1, NRECA does not believe it is necessary to include the Balancing Authority as an
applicable entity in this standard.
NRECA agrees that the 36-month time frame for review is reasonable.
NRECA is does not believe that it is necessary to develop a separate GMD standard to address requiring Operating
Procedures for GMD events. Criteria for addressing such events can easily be added to existing standards that require
entities to have Operating Procedures. Suggesting a new standard that has similar requirements as existing standards does
not adhere to the spirit of the P81 initiative to eliminate unnecessary duplicative requirements. Examples of requirements
that could be revised to address GMD events are: IRO-014-1 R1 requires the RC to have operating procedures, processes
or plans for activities that require notification or exchange of information with other Reliability Coordinators. TOP-004-2 R6.1
requires the TOP to have policies and procedures for monitoring and controlling voltage levels and reactive power flows. R5
- NRECA agrees that it is reasonable to require that a copy of an applicable entity’s GMD Operating Procedures is in its
primary control room and any applicable backup control rooms so that it is available to its operating personnel prior to its
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
implementation date. In the Time Horizon designation for the requirements of this standard, the “Long Term Planning”
horizon should be removed. As written, this standard addresses Operating Procedures to address Real-time events not
those that meet the criteria for a “Long Term” event.
Yes
NRECA agrees that the SAR as drafted provides a scope to address the directives in Order No 779, but believes as
explained in response to Question 5 the directives could be addressed by modifying existing standards as an alternative to
developing a new standard.
No
As explained in response to Question 1, NRECA does not believe it is necessary to include the Balancing Authority as an
applicable entity in this standard.
Yes
As explained in response to Question 1, it is important that any standard that is developed addressed regional geographic
differences associated with the impacts of GMD in the requirements of the standard. Present data does not support that the
potential for equipment damage resulting in a GMD event is the same for a cooperative in the Northeast and a cooperative
in the Southeast.
Group
SPP Standards Review Group
Robert Rhodes
No
Please refer to our comment in Question 7 directed toward applicability in the SAR.
Yes
While we concur that R1 addresses the FERC directive, we have some reservations with the use of the word ‘coordinated’
in R1.2 especially along the lines of what specifically will be required by the responsible entities to show coordination.
Hopefully, the Reliability Coordinator will provide those details in his processes. Additionally, we would encourage the
NERC Operating Reliability Subcommittee to ensure consistency in the processes used by the Reliability Coordinators
throughout NERC.
Yes
No
To address timing issues in R5, we suggest inserting the word ‘current’ between the ‘a’ and ‘copy’ and deleting the phrase
‘so that it is available to its operating personnel prior to its implementation date’. R1 would then read Each Transmission
Operator shall have a current copy of its GMD Operating Procedures in its primary control room and any applicable backup
control rooms. For consistency with EOP-005, we would suggest that the VRF for R5 be reduced to Low. This is an
administrative requirement and does not merit a Medium VRF. Additionally, we wonder why the Reliability Coordinator is
not required to have a copy of its GMD Operating Plan in its primary and backup control centers.
Delete the phrase ‘and submit(ted) them for approval’ from the VSLs in R4. R4 does not require approval.
Yes
The SAR, as well as the draft standard, refer to the BPS. Given the restrictions as proposed in the standard on transformers
with high-side terminals of 200 kV and above, wouldn’t the reference be more appropriate to the BES?
No
The Functional Model does not assign transformer operation to the Balancing Authority yet the drafting team makes a
connection between transformers and the Balancing Authority by incorporating the Balancing Authority in the Applicability
Section. Why did the drafting team make this decision? Shouldn’t the Balancing Authority be removed from the Applicability
Section since it is concerned with balancing generation to load and not operating transformers? The Balancing Authority
already has procedures to assist it whenever load or generation within its Balancing Authority Area is lost. It’s reason for the
loss is immaterial to the Balancing Authority, the procedures it has to cover this situation would be similar regardless of the
cause. In any event, the Balancing Authority has no responsibility to mitigate issues associated with a transformer within its
Balancing Authority Area. That functionality resides with the Transmission Operator.
No
While we are concerned with the intent of continent-wide requirements, if accomplished as proposed by the drafting team
with flexibility provided for responsible entities to tailor their response to both stages of standard development to their risk
and exposure based on their geography, geology and system topology, then regional variances may not be needed.
Otherwise, regional waivers or exemptions may be appropriate.
Yes
We foresee the need for a study/modeling group similar to the MWG which would assemble the appropriate data base upon
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
which collaborated studies, similar to the interregional transfer capability studies being done today, would be conducted.
The results of those studies would then also be made available to any responsible entity for purposes of GMD assessment.
Individual
Bill Fowler
City of Tallahassee
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission Operators and Balancing
Authorities are coordinated and compatible. TAL recommends replacing “all TOs and BAs” with “applicable TOs and BAs”.
Additionally, the RC has to prove all the plans are “coordinated and compatible”. This was a large undertaking for the EOP006 restoration plans, and will be equally burdensome to the RC for these plans.
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark studies” as required
in Stage 2. It would seem appropriate to have the studies first in order to write the procedures as required in Stage 1. The
Stage 2 could remain with the incorporation of equipment for the mitigation of the GIC. The white paper for the 200kV
threshold has not been made available as was promoted on the July 30 webinar. How can we vote when the reference is
not available?
Individual
Scott Langston
City of Tallahassee
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission Operators and Balancing
Authorities are coordinated and compatible. TAL recommends replacing “all TOs and BAs” with “applicable TOs and BAs”.
Additionally, the RC has to prove all the plans are “coordinated and compatible”. This was a large undertaking for the EOP006 restoration plans, and will be equally burdensome to the RC for these plans.
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark studies” as required
in Stage 2. It would seem appropriate to have the studies first in order to write the procedures as required in Stage 1. The
Stage 2 could remain with the incorporation of equipment for the mitigation of the GIC. The white paper for the 200kV
threshold has not been made available as was promoted on the July 30 webinar. How can we vote when the reference is
not available?
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
BPA’s position is that the primary entities responding to GMD events are the TOPs and BAs. BPA believes the RC should
be required to develop the criterion for their Operating Plan in direct coordination with the TOPs and BAs in their area in
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order to avoid the RC developing a plan that may not be compatible with the region. Additionally, the RC should be the
primary source of space/weather information and be required to disemminate that information to the TOPs and BAs in their
area.
Yes
Yes
BPA agrees that operational procedures should be put in place but they will not have sufficient analysis of the full impact of
certain actions due to certain technologies not being available at this point. Specifically, the reactive and thermal impacts of
GMD on transformers.
Yes
Yes
No
No
Individual
Karen Webb
City of Tallahassee - Electric Utility
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission Operators and Balancing
Authorities are coordinated and compatible. TAL recommends replacing “all TOPs and BAs” with “applicable TOPs and
BAs”. Additionally, the RC has to prove all the plans are “coordinated and compatible”. This was a large undertaking for the
EOP-006 restoration plans, and will be equally burdensome to the RC for these plans.
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark studies” as required
in Stage 2. It would seem appropriate to have the studies first in order to write the procedures as required in Stage 1. The
Stage 2 could remain with the incorporation of equipment for the mitigation of the GIC. The white paper for the 200kV
threshold has not been made available as was promoted on the July 30 webinar. This reference is valuable to entity wishing
to make an informed vote.
Individual
Bret Galbraith
Seminole Electric
No
Seminole asks the SDT to add language to the Standard that indicates that Industry and NERC intend to allow for
consideration of various entity specific characteristics in developing a GMD Operating Plan. Seminole is aware that this is
the intent of the SDT and therefore Seminole proposes the following language, or similar language, be added in each
Requirement requiring an Entity to develop a type of GMD Operating Plan and/or set of Operating Procedures: “An Entity
can take into consideration such entity-specific factors such as geography, geology, and system topology in developing a
GMD Operating Plan/set of Operating Procedures.” Seminole believes that this is not clear in the Requirement and wishes
that the NERC SDT specifically state the ability for an entity to tailor their plans and/or procedures to their environment. In
addition, the suggested language is pulled from the SAR for this project.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Group
Colorado Springs Utilities
Kaleb Brimhall
No
• GOP should also be included. • Voltage level not a good indicator of susceptibility to ground induced currents. Possibly
latitude, transmission line orientation or transmission line length a better indicator. If voltage were to be used, think higher
voltage should be considered.
Yes
Yes
Yes
Comments on Requirement 1: • In need to include a requirement for the RC to acquire and disseminate space weather
information to the applicable entities within their footprint. Comments on Requirement 3: • From the glossary; Operating
Procedure (in part): "The steps in an Operating Procedure should be followed in the order in which they are presented";
Operating Process (in part): "An Operating Process includes steps with options that may be selected depending upon Realtime conditions." The language in the Standard will be what is audited to, notwithstanding what any individual utility may
titles their documents. The actions which may be required during a GMD event are far better presented in an Operating
Process (as defined) than an Operating Procedure (as defined). There is no way that a TOP could follow the exact same
step-by-step procedure for all GMD eventualities, but that is what the "Operating Procedure" term demands. Comments on
Requirement R3.1: • Need to eliminate the requirement to acquire space weather information in R3.1, and have it a part of
the information that the RC would disseminate to ensure consistency and coordination from the RC. Comments on
Implementation Plan: 1. Need to ensure that RC develops and disseminates their plan 1st with time included to incorporate
RC plan into BA/TOP/GOP plans. 2. Implementation period needs to be extended from 6 months to 12 months.
Abstained from Commenting.
Yes
Yes
1. Variances are absolutely going to be necessary based on geography, geology, and system topology.
Abstained from commenting.
None
Group
JEA
Tom McElhinney
No
The applicable entities should’t not include the BA but needs to include the GOs. Generator step up transformers are more
critical to BES reliability than substation step down transformers. Only BES transformers should be included.
No
A vulnerability study is required before good operating procedures can be developed
No
BA should be removed
Yes
Yes
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Yes
No
Individual
David Gordon
Massachusetts Municipal Wholesale Electric Company
Agree
American Public Power Association (APPA)
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC Review Group
Group
Santee Cooper
S. Tom Abrams
Yes
Recommend the SDT consider changing he high side terminal voltage on transformers to greater than 300 kV. The focus of
the standard should be at higher voltages where the line length makes the lines more vulnerable to geomagneticallyinduced currents.
Individual
Bryan Griess
Transmission Agency of Northern California
TANC appreciates the performance flexibility that has been built into the current draft of this standard, but has concerns
regarding the approximately six month implementation period between its approval and effective date. Of particular concern
is the ability for each Reliability Coordinator to ensure coordination and compatibility between its GMD Operating Plan and
the GMD Operating Procedures for all Transmission Operators and Balancing Authorities in its footprint during such an
abbreviated period. As this initiative moves forward, TANC requests that NERC continue to carefully consider the scope of
entities and assets that will be subject to this and subsequent standards so that the costs borne by the industry are
commensurate with the anticipated benefit to reliability.
Group
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Agree
NRECA SERC
Group
Foundation for Resilient Societies
William R. Harris
No
Standards relating to Operating Procedures should apply to high side Transformers of 100 kV or higher. Despite higher
resistance, transformers in the 100 kV to 200 kV range contribute a significant proportion of GICs that can destabilize the
grid. TJ Overbye et al (2012)estimate less than 60% of total MVAR is captured in New England and Michigan if
transmission under 230 kV is excluded from protection. New transformers in the 100 kV to 200 kV range are projected by
the Energy Information Administration at about 20% of all new EHV transmission mileage planned for the 2012-2018 period.
NERC must include generating entities, because existing studies suffice to demonstrate both vulnerability of GSU
transformers operated by Generating entities and need for equipment monitoring at generator stators, and related operating
procedures to protect generators in severe geomagnetic storms. GSU Generators are at greater risk than generally
recognized. See studies by Legro, Abi-Samra and Tesche at ORNL (1985); Walling & Kahn (1991); J G Kappenman, Storm
Analysis Report R-112, section 8 (2011); and Luis Marti, "Generator Thermal Stress during a Geomagnetic Disturbance"
(2013). Of critical importance, the President of the United States has existing legal authority to order the de-energizing of
electric generating facilities that are oil or gas-fired if an emergency so requires. To utilize this authority upon confirmed
space warning of a severe solar geomagnetic storm, it is essential that all generating entities serving the bulk power system
be included in emergency operating procedure standards; their personnel be trained to validate and confirm de-energizing
orders and procedures (and re-energizing procedures), with a multi-day strategic warning but only tens of minutes for
tactical order, validation, and execution. Because most of the generating facilities serving the bulk power system are not
now equipped with protective equipment that would enable these facilities to "operate through" a severe solar geomagnetic
storm, it is essential that generating entities be included in the Operating Procedure coverage and standards. Further, the
Nuclear Regulatory Commission has existing authority to order de-energizing and safe shutdown of the 102 NRC licensed
nuclear power plants in the U.S. or a subset that are especially affected by a particular GMD event. Generating entities may
need to review operating procedure options for rapid shutdown of generators if GSU transformers are not equipped with
protective hardware. Beyond the practical necessity of including transformers and transmission equipment in the 100 kV to
200 kV range, FERC Order 779 applies to the entire bulk power system, which is now defined as commencing at 100 kV or
above and not 200 kV or above. It would be illegal for NERC to exclude a significant proportion of the transmission line
mileage (for many utilities more than half total EHV transmission mileage). Even if EHV transformers above 200 kV are later
protected with neutral ground blocking equipment, leakage of GICs from lower voltage equipment will add significant Mvar
into regional grids. FERC intended standards to protect the entire bulk power system of 100 kV or higher; NERC's
participating entities should respect and support this federal policy.
Yes
No
Reason: Earlier comments on the Operating Procedure Templates submitted by the Foundation for Resilient Societies were
ignored, and not addressed on their merits by the GMD Task Force management and by the NERC Planning Committee.
See our previous comments at: https://resilientsocieties.org/images/Comments Operating Procedure Template NERC
GMDTF Phase 2 Rev1.pdf.
Yes
The Foundation for Resilient Societies has concerns that the NERC Planning Application Guide, developed without full
public access to the related model assumptions, will mis-characterize geomagnetic latitudes with geographic latitudes; and
will result in scientifically invalid assumptions that the NERC modeled "operating procedures" will suffice without need for
hardware protections. For our Foundation review of the Draft NERC GMD Planning Application Guide, our review dated
August 9, 2013, see:
http://resilientsocieties.org/images/Resilient_Societies_Comments_on_GMD_Planning_Application_Guide _Final.pdf.
Yes
Yes
Yes
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
For effective operating procedures implemented through regional balancing authorities, improved near-real-time GIC
monitoring will be needed for all GSU transformers, SVC equipment, and major generating equipment at risk in severe solar
storms. Regional balancing authorities will require improved near-real-time monitoring to prepare and protect ready
reserves. Communications must be designed to operate even during severe solar storms. Regional balancing authorities
will need to be in contact with the White House Situation Room and federal command centers elsewhere.
For concerns of the Foundation for Resilient Societies, see our website at www.resilientsocieties.org. A case study of Maine
and ISO-New England utilizing recently revised operating procedures documents our concern that regional "ready reserves"
in a severe geomagnetic storm are likely to be inadequate due to a combination of vulnerable long distance HVDC
transmission lines, a record of SVC "trips" during only moderate solar storms, and unprotected generating equipment in
New England, where high GICs are recorded.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
Yes
Yes
Yes
We agree with the proposed requirement. However, there currently exists a similar requirement in IRC-005-3.1a, R3, which
says: R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing Authorities are aware of GeoMagnetic Disturbance (GMD) forecast information and assist as needed in the development of any required response plans.
With the introduction of the EOP-010 standard, specifically Requirement R3, the TOP and BA will have operating
procedures in place and be required to monitor GMD activities on an ongoing basis. We question the need to keep R3 of
IRO-005-3.1a. If the latter is deemed redundant after the adoption of the EOP-010 standard, we suggest the SDT propose
retiring R3 of IRO-005-3.1a. If R3 is to be retained, then it does not mention “applicable” BAs and TOPs, which it should.
No
Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain and implement operations
plan to mitigate GMD effects. Whether or not there is a hard copy, or electronic copy for that matter, in the control room
and/or the backup control centre is unimportant and irrelevant. In order that the Responsible Entities implement the plan to
comply with the standard requirements, operatinbg personnel needs to be provided and have access to the plan itself,
regardless of where and how it is placed. We suggest removing R5.
No
If the Stage II assessment is done from a wide-area perspective, how would it work from a functional entity perspective?
Other than in the ERCOT interconnection, which functional entity would be responsible at the interconnection level? No
relevant functional entity has an interconnection-wide geographic scope?
Yes
No
No
Individual
Mauricio Guardado
Los Angeles Department of Water and Power
No
Reliable operation of the BES requires that GMD be responded to by all parties with equipment electrically connected to the
interconnection. The NERC 2012 Special Reliability Assessment Interim report: Effects of Geomagnetic Disturbances
(GMDs) on the Bulk Power System” proposes the steps outlined below for development of effective mitigation of GMDs,
based on the fact that measures taken piece meal by one or more stakeholders (as opposed to those based on engineering
studies and operation of the interconnection as a whole) will shift, and may concentrate, Geomagnetically Induced Currents
(GICs) causing damage and possibly uncontrolled separation, or cascading failure of other system elements. Phase One –
Assess and Baseline Risk Phase Two – Perform Technical and Programmatic Analysis Phase Three – Develop Integrated
Solutions Phase Four – Implement Solutions and Adjust System Procedures It seems that EOP-010 is bringing
requirements for operational procedures to mitigate GMDs before the relevant studies are complete, and then update them
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
periodically as data improves. To this end NERC has developed the “Geomagnetic Disturbance Operating Procedure
Template” for Transmission Operators, which suggests a run back on equipment limits to leave headroom for the GICs.
Given the above, and the fact that Generator Step Up (GSU) transformer (primaries >200kV) windings tend to have the
highest currents of any BES transformer, Generator Operators should be included in stage 1 standards with the
recommendation that they also have a mandatory runback to maintain D curve headroom on the generators (which will
probably be called on to meet extra VAR requirements) and headroom on transformer limits to accommodate GICs.
No
Even at this early stage of standard development it is generally agreed that system wide approaches are required to
prevent equipment damage and the possibility of uncontrolled separation, or cascading outages, and that partial measures
are likely to relocate and or concentrate the effects of GIC’s, therefore R1 lacks a crucial element to insure grid reliability. At
a minimum, the GMD operating plan should also include: R1.1.3 A process for the Reliability Coordinator to determine the
need for and invoke the GMD operating procedures for a specified level response by a specified time, and a means of
verifying all parties within the Reliability Coordinator Area are in compliance before that specified time. Also a process to
determine and invoke an end to GMD events. Note: see R1 comment, R1.1.2 should include Generator Operators in
addition to Transmission Operators and Balancing Authorities.
No
While it is agreed that BAs and TOPs and GOs should develop and maintain Operating Procedures to mitigate the effects of
GMD events, doing so will protect the equipment and interest of said BA, TOP or GO, but WILL NOT insure grid reliability or
the elimination of conditions which could lead to uncontrolled separation, or cascading outages. These plans must be
reviewed by the RC’s technical team for their effect on other members of the interconnection, and approved or modified to
meet grid reliability considerations. Such modifications must be acknowledged and agreed to by the Stakeholders, and
invoked when directed by the RC (R3.3.1 and R3.3.3 are inappropriate and should be replaced by the suggested R1.1.2
above in question 2 comments).
Yes
Periodic review is important. LADWP would like to know the basis for the time period of 36 months.
Also, lacking is a clear statement that a directive from the RC (that GMD level X procedures are being invoked) needs to act
as a signal that the market is suspended for the duration of the directive. During such GMD events, Grid Reliability will
depend on the ability to redispatched generation to accommodate new conditions and operating limits. A means of
establishing appropriate prices for power and Transmission rights should be established in advance and agreed to by all
parties as a condition of GMD Operating Plan approval.
LADWP does not currently have a comment on this question.
LADWP does not currently have a comment on this question.
LADWP does not currently have a comment on this question.
LADWP does not currently have a comment on this question.
LADWP does not currently have a comment on this question.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
In general, we agree with R1 & R1.1. However, we feel that R1.2 should be modified. Instead, we recommend the
requirement read something like this: [1.2 A process for the Reliability Coordinator to coordinate GMD Operating
Procedures and mitigating steps or tasks with Transmission Operators and Balancing Authorities in the Reliability
Coordinator Area.]
No
Recommend revising R3.1. It isn’t clear as to what periodicity that an entity should be collecting and disseminating this
information. Also, it is unclear as to what would qualify as a source to meet this requirement (i.e. is any ‘space weather’
source acceptable?). Suggest removing this requirement and indicate in prior requirement (R1) that RCs have the
responsibility of collecting and sharing space weather information with TOPs and BAs, and RCs must subscribe to an
authoritative space weather source.
Yes
The current IRO-005-3.1a R3 requires RCs to notify TOPs and BAs of certain GMD events. Consider deleting this
requirement in IRO-005-3.1a as part of this implementation plan and add something in this standard (EOP-010) requiring
RCs to make that notification. The pending approval of IRO-005-4 removed the explicit requirement, but development
history indicates that it considers GMD to have an Adverse Reliability Impact that would require RC notification to entities.
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
Individual
Angela P Gaines
Portland General Electric Co
Agree
PGE supports WECC's position regarding the standard as it relates to the implementation timeframes.
Group
El Paso Electric Company
Pablo Onate
EPE generally supports stage 1 of Project 2013-03: Geomagnetic Disturbance Mitigation. EPE is concerned with the short
implementation period of six calendar months following applicable regulatory approval and would like to see a 1 yearlong
implementation period instead.
Individual
Rhonda Bryant
El Paso Electric Company
EPE generally supports stage 1 of Project 2013-03: Geomagnetic Disturbance Mitigation. EPE is concerned with the short
implementation period of six calendar months following applicable regulatory approval and would like to see a 1 year long
implementation period instead.
Individual
Joe Tarantino
Sacramento Municipal Utility District
No
~1. The applicability ought to be clear that the standard refers to only BES transformers and not step-down transformers to
distribution. ~2. Referring to the Oak Ridge national Laboratory 319 report, the winding(s) in question needs to be wye
connected and not delta connected for ground current to flow. The geomagnetically induced current (GIC) is ground current.
Hence, the applicability ought to specify transformers with "wye" connected winding(s) above a certain threshold voltage.
Three phase core transformers are much less likely to saturate and result in MVAR demands about 25% of that of three
single core transformers. Hence, the applicability for > 200 kV and < 400 kV (i.e., the 230 and 345 kV transformers) ought to
be limited to single phase core transformers.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
No
No
Every 36 months is too short of a time-frame. It would be more appropriate to have a review of a potential plan, if indeed
needed, when system configurations warrant a review. The review period should be set by the entity, IF there is even a
concern.
SMUD also has concerns with the implementation period and questions whether or not six months is adequate time for the
BA and TOP to develop the required GMD Operating Procedures and for the RC to develop the required Plan to coordinate
those GMD Operating Procedures. SMUD also encourages the SDT to consider the GMD threshold application to be raised
to 300+kV, and also encourages the Project 2013-03 Standard Drafting Team to consider the comments submitted by
Florida Municipal Power Agency (FMPA) related to applicability of the standard.
No
SMUD is unaware of WECC any regional variance.
No
Individual
Laurie Williams
PNM Resources
Agree
WECC Staff
Individual
Nathan Mitchell
American Public Power Association
No
APPA appreciates the SDT’s effort to limit the applicability of the proposed standard by setting a voltage threshold for TOPs
and BAs. On the July 30th webinar the SDT stated that a technical whitepaper was being developed to justify the 200 kV
threshold. APPA will hold any comments on the voltage threshold until after the whitepaper is released. We request that the
whitepaper be provided soon so the industry has time to discuss this threshold prior to the final comment and ballot period.
APPA recommends that the SDT modify the applicability section wording to replace “transformers” with “BES transformers.”
Including only BES transformers will make the applicability of the standard clear. Some Transmission Owners may have
transformers with high side voltage above 200 kV, but they are connected radially so are not part of the BES. These
transformers should be out of scope for this standard.
No
APPA suggests that the word “all” in Requirement R1.2, be replaced with the word “applicable.” APPA believes using the
word “all” in this context will bring into applicability TOs and BAs that have transformers below the 200 kV threshold.
Replacing “all” with “applicable” will limit confusion and avoid conflict with the applicability section of the standard. APPA is
also concerned with the words “coordinated and compatible” in R1.2. On the July 30th webinar the SDT stated that a full
scale power flow analysis would be the ideal way for the RC to determine compatibility of various plans. APPA is concerned
with the cost to TOs and BAs of meeting this “ideal” therefore we suggest that the SDT give guidance on acceptable
alternatives.
Yes
Yes
Yes
Yes
No
No
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual
Linda Jacobson-Quinn
Farmington Electric Utility System
Yes
No
Recommend rewording R1.2 ”A process for the Reliability Coordinator to coordinate GMD Operating Procedures and
mitigating steps or tasks with Transmission Operators and Balancing Authorities in the Reliability Coordinator Area.“ FEUS
has concerns with how the RC would ensure ALL the TOP and BA plans are coordinated and compatible. In addition, FEUS
is unclear what demonstrates a plan is compatible.
No
Recommend revising 3.2. to the following, “The steps or tasks to be employed by System Operators that are coordinated
with its Reliability Coordinator to mitigate the effects on the system from GMD events.” FEUS agrees it is pertinent
mitigating activities are coordinated; however, we believe this level or coordination should be in line with what is expected
for coordination activities during a restoration.
Yes
FEUS appreciates the work by the SDT team to allow entities flexibility when developing their operating procedures for
mitigating GMD. The flexibility allows for entities to develop the plan that works with their system
Yes
Yes
No
No
Individual
Rick Terrill
Luminant Generation
Yes
Yes
Yes
Yes
Luminant has voted Negative as the posting and balloting of the GMD proposed standard did not follow the NERC Rules of
Procedure. Luminant appreciates the technical work of the Ad Hoc group but believes the standard should have been
posted for comments only, instead of being posted for balloting.
Individual
Scott Berry
Indiana Municipal Power Agency
Agree
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
IMPA supports the comments submitted by Frank Gaffney from Florida Municipal Power Agency.
Individual
Mauricio Guardado
Los Angeles Department of Water and Power
No
LADWP is making a correction to Question 1 and therefore is resubmitting its comments from yesterday. Please take these
comments and regard the ones from yesterday.
__________________________________________________________________________________________________
_ Reliable operation of the BES requires that GMD be responded to by all parties with equipment electrically connected to
the interconnection. The NERC 2012 Special Reliability Assessment Interim report: Effects of Geomagnetic Disturbances
(GMDs) on the Bulk Power System” proposes the steps outlined below for development of effective mitigation of GMDs,
based on the fact that measures taken piece meal by one or more stakeholders (as opposed to those based on engineering
studies and operation of the interconnection as a whole) will shift, and may concentrate, Geomagnetically Induced Currents
(GICs) causing damage and possibly uncontrolled separation, or cascading failure of other system elements. Phase One –
Assess and Baseline Risk Phase Two – Perform Technical and Programmatic Analysis Phase Three – Develop Integrated
Solutions Phase Four – Implement Solutions and Adjust System Procedures It seems that EOP-010 is bringing
requirements for operational procedures to mitigate GMDs before the relevant studies are complete, and then update them
periodically as data improves. To this end NERC has developed the “Geomagnetic Disturbance Operating Procedure
Template” for Transmission Operators, which suggests a run back on equipment limits to leave headroom for the GICs.
Given the above, and the fact that Generator Step Up (GSU) transformer (primaries >20kV) windings tend to have the
highest currents of any BES transformer, Generator Operators should be included in stage 1 standards with the
recommendation that they also have a mandatory runback to maintain D curve headroom on the generators (which will
probably be called on to meet extra VAR requirements) and headroom on transformer limits to accommodate GICs.
No
Even at this early stage of standard development it is generally agreed that system wide approaches are required to
prevent equipment damage and the possibility of uncontrolled separation, or cascading outages, and that partial measures
are likely to relocate and or concentrate the effects of GIC’s, therefore R1 lacks a crucial element to insure grid reliability. At
a minimum, the GMD operating plan should also include: R1.1.3 A process for the Reliability Coordinator to determine the
need for and invoke the GMD operating procedures for a specified level response by a specified time, and a means of
verifying all parties within the Reliability Coordinator Area are in compliance before that specified time. Also a process to
determine and invoke an end to GMD events. Note: see R1 comment, R1.1.2 should include Generator Operators in
addition to Transmission Operators and Balancing Authorities.
No
While it is agreed that BAs and TOPs and GOs should develop and maintain Operating Procedures to mitigate the effects of
GMD events, doing so will protect the equipment and interest of said BA, TOP or GO, but WILL NOT insure grid reliability or
the elimination of conditions which could lead to uncontrolled separation, or cascading outages. These plans must be
reviewed by the RC’s technical team for their effect on other members of the interconnection, and approved or modified to
meet grid reliability considerations. Such modifications must be acknowledged and agreed to by the Stakeholders, and
invoked when directed by the RC (R3.3.1 and R3.3.3 are inappropriate and should be replaced by the suggested R1.1.2
above in question 2 comments).
Yes
Periodic review is important. LADWP would like to know the basis for the time period of 36 months.
Also, lacking is a clear statement that a directive from the RC (that GMD level X procedures are being invoked) needs to act
as a signal that the market is suspended for the duration of the directive. During such GMD events, Grid Reliability will
depend on the ability to redispatched generation to accommodate new conditions and operating limits. A means of
establishing appropriate prices for power and Transmission rights should be established in advance and agreed to by all
parties as a condition of GMD Operating Plan approval.
LADWP does not currently have a response for this question.
LADWP does not currently have a response for this question.
LADWP does not currently have a response for this question.
LADWP does not currently have a response for this question.
LADWP does not currently have a response for this question.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Monitoring
The Project 2013-03 Drafting Team thanks all commenters who submitted comments on the draft
stage 1 Standard (EOP-010-1) and Standard Authorization Request (SAR) addressing stages 1 and 2.
Project 2013-03 will develop requirements for registered entities to employ strategies that mitigate
risks of instability, uncontrolled separation and Cascading in the Bulk-Power System caused by GMD in
two stages as directed in FERC Order No. 779:
1. Stage 1 standard(s) will require applicable registered entities to develop and implement
Operating Procedures with predetermined and actionable steps to take prior to and during
GMD events which take into account entity-specific factors that can impact the severity of GMD
events in the local area.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going
assessments of the potential impact of benchmark GMD events on their respective system as
directed in Order 779. The Stage 2 standard(s) must identify benchmark GMD events that
specify what severity GMD events applicable registered entities must assess for potential
impacts. If the assessments identify potential impacts from benchmark GMD events, the
standard(s) will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of benchmark GMD events.
The standard and SAR were posted for a 45-day formal comment period from June 27, 2013 through
August 12, 2013. Stakeholders were asked to provide feedback on the standard and associated
documents through a special electronic comment form. There were 85 sets of responses, including
comments from over 225 different people from approximately 140 companies representing all 10 of
the Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the project page.
Summary Consideration:
The drafting team has revised the standard to incorporate a number of stakeholder recommendations
that the drafting team believes are appropriate to improve the standard. As a result of comments
received, the drafting team has identified the need to make significant changes to the standard.
Although Section 4.12 of the NERC Standard Processes Manual indicates that the drafting team is not
required to respond in writing to comments from the previous posting when it has identified the
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
need to make significant changes to the standard, the drafting team is providing summary responses
to the comments received in order to facilitate stakeholder understanding.
A summary response follows each question. Please note that because common issues were grouped
together in the summaries, an individual's comment may have been addressed in the summary for a
question that is different from the question in which they submitted the comment; the drafting team
encourages reviewers to read all summary responses.
The drafting team made the following changes after reviewing stakeholder comments:
A new Requirement R2 has been added to the standard, which would require RCs to
disseminate space weather forecast information to TOPs in their Reliability Coordinator Area.
IRO-005-3.1a Requirement R3 currently provides this obligation. However, the NERC Board has
approved IRO-005-4 which would result in retirement of the requirement. The new
Requirement R2 in EOP-010-1 will maintain the RC’s responsibility for providing space weather
forecast information. The implementation plan includes guidance for making the new
Requirement R2 effective to avoid a situation where both IRO-005-3.1a Requirement R3 and
EOP-010-1 Requirement R2 are effective at the same time.
In response to stakeholder comments that certain Requirements met Paragraph 81 criteria,
administrative requirements for reviewing of GMD Operating Plans and Procedures within a 36month period and for having a copy in the control room were removed.
Several changes in language were made to improve the clarity of requirements and measures.
Applicability:
o Balancing Authorities (BA) have been removed from the applicable functional entities
because there are no additional steps or tasks for a BA to perform beyond their normal
balancing functions to mitigate GMD events. The BA is not expected to initiate specific
mitigating actions during a GMD event and would instead respond to the direction of the
Transmission Operator (TOP) and Reliability Coordinator (RC). Existing standards provide
the required authority for action. A whitepaper with the drafting team's analysis is
posted on the project page.
o The applicable TOP has been clarified to include only those that operate power
transformers with a high side wye-grounded winding with terminal voltage greater than
200 kV. This applicability statement describes the functional entity in terms of the
assets that they operate, which could include non-BES assets. The applicability
statement is not intended to define equipment to be protected by the Operating
Procedures. The drafting team views 200 kV as the minimum network voltage for which
a reliability benefit can be expected from the application of GMD Operating Procedures.
A whitepaper with the drafting team's analysis is posted on the project page.
Although some stakeholders suggested that Generator Operators (GOPs) be added to the standard as
applicable entities, the drafting team maintains that a GOP's Operating Procedures specifically to
mitigate the effects of GMD would need to be supported by an equipment-specific study and might
Consideration of Comments: Project 2013-03 | August 30, 2013
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
require the use of GMD monitoring equipment. Because it is not reasonable to assume that all GOPs
have such studies or monitoring equipment, GOPs have not been added to EOP-010-1. Consistent with
Order No. 779, vulnerability assessments and mitigation plans will be addressed in stage 2 of Project
2013-03, and Generator Owners (GO) and GOPs will be considered for applicability with stage 2. A
whitepaper with the drafting team's analysis supporting the applicability of EOP-010-1 is posted on the
project page.
Some stakeholders also commented that the six-month implementation period was too short. The
drafting team is sympathetic to the challenge of completing the necessary coordination in a six-month
time period. However this implementation period was suggested in FERC Order No. 779 and the
drafting team lacks strong justification for a specific longer period.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments: Project 2013-03 | August 30, 2013
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Index to Questions, Comments, and Responses
1.
The SDT is proposing that the draft stage 1 Standard should apply to Reliability Coordinators,
Balancing Authorities with a Balancing Authority Area that includes any transformer with high
side terminal voltage greater than 200 kV, and Transmission Operator with a Transmission
Operator Area that includes any transformer with high side terminal voltage greater than 200
kV. Do you agree that the SDT has correctly identified the applicable functional entities in the
initial draft stage 1 Standard? If you do not agree, or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................17
2.
In Requirement R1, the SDT is proposing to require Reliability Coordinators to develop,
maintain, and implement a GMD Operating Plan. This coordinating role for the RC is based on
the functional model and addresses the Order No. 779 directive to consider the coordination
of Operating Procedures across regions by a functional entity with a wide-area view. The
defined term "Operating Plan" provides the RC with latitude to determine specific activities
necessary to achieve this goal. Do you agree that the SDT has correctly addressed this
directive? If you do not agree that this requirement addresses the directive, or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ...................................................................................36
3.
In Requirement R3, the SDT is proposing to require each applicable Transmission Operator
and Balancing Authority to develop, maintain, and implement GMD Operating Procedures.
The draft Standard is intended to allow each entity to develop its own procedures based on
entity-specific factors as directed in Order No. 779. Do you agree that the SDT has correctly
addressed the stage 1 directives in Order No. 779? If you do not agree that this requirement
addresses the directive, or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments. .........................53
4.
In Requirements R2 and R4 the SDT is proposing to require applicable entities to review their
GMD Plans/Operating Procedures every 36-months. This periodicity would ensure
improvements in the scientific understanding of GMDs can be incorporated into Operating
Procedures in a timely manner as directed in Order No. 779. In Requirement R5, the SDT is
proposing to require each applicable Transmission Operator and Balancing Authority to have
a copy of its GMD Operating Procedures in its Primary and Back-up Control Rooms, which is
consistent with other EOP reliability standards. Do you agree that the SDT has correctly
addressed the directives in Order No. 779 in a manner that is good for reliability with these
requirements? If you do not agree, or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments. ...........65
5.
If you have any other comments on this draft Standard that you haven’t already mentioned
above, please provide them here. ................................................................................76
Consideration of Comments: Project 2013-03 | August 30, 2013
4
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
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Russel Mountjoy
MRO NERC Standards Review Forum (NSRF)
Additional Organization
Region Segment Selection
1.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
2.
Dan Inman
Minnkota Power Cooperative
MRO
1, 3, 5, 6
3.
Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
4.
Kayleigh Wilkerson Lincoln Electric System
MRO
1, 3, 5, 6
5.
Jodi Jensen
Western Area Power Administration
MRO
1, 6
6.
Joseph DePoorter
Madision Gas and Electric
MRO
3, 4, 5, 6
7.
Ken Goldsmith
Alliant Energy
MRO
4
8.
Marie Knox
Midcontinent Independent System Operator MRO
2
9.
Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5, 6
Great River Energy
MRO
1, 3, 5, 6
10. Mike Brytowski
X
2
X
3
X
4
X
5
X
6
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Scott Bos
Muscatine Power and Water
MRO
1, 3, 5, 6
12. Scott Nickels
Rochester Public Utilities
MRO
4
13. Terry Harbour
MidAmerican EnergyCompany
MRO
1, 3, 5, 6
14. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
15. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
2.
Stuart Goza
Group
SERC OC Review Group
2
3
X
X
X
X
4
5
X
X
Additional Member Additional Organization Region Segment Selection
1.
Michael Lowman
Duke Energy
SERC
1, 3, 5, 6
2.
Tom Pruitt
Duke Energy
SERC
1, 3, 5, 6
3.
Andrew Witmeier
Midwest ISO
SERC
2
4.
Terry Bilke
Midwest ISO
SERC
2
5.
Wayne Van Liere
LGE-KU
SERC
1, 3, 5, 6
6.
Scott Walker
TVA
SERC
1, 3, 5, 6
7.
Steve Corbin
SERC
SERC
10
8.
Jeff Harrison
AECI
SERC
1, 3, 5, 6
9.
Danny Dees
MEAG Power
SERC
1, 3, 5
10. Mike Bryson
PJM
SERC
2
11. Ray Phillips
AMEA
SERC
4
12. Tim Hattaway
PowerSouth
SERC
1, 5
13. Jim Case
Entergy
SERC
1, 3, 6
14. Patrick McGovern
Georgia Transmission
SERC
1
15. Scott Brame
NCEMCS
SERC
1, 3, 4, 5
16. Chris Wagner
Santee Cooper
SERC
1, 3, 5, 6
17. Greg McKinney
EKPC
SERC
1, 3, 5
18. William Berry
OMU
SERC
3
19. Sammy Roberts
Duke Energy
SERC
1, 3, 5, 6
20. Ben Deutsch
SERC
SERC
10
3.
David Thorne
Group
Pepco Holdings Inc & Affiliates
Additional Member Additional Organization Region Segment Selection
1. Mark Godfrey
Pepco Holdings Inc
RFC
1, 3
2. Jane Verner
Pepco
RFC
1, 3
Consideration of Comments: Project 2013-03 | August 30, 2013
6
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Group
Sasa Maljukan
Hydro One Networks Inc.
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
5.
Hydro One Networks Inc. NPCC 1, 3
Group
Connie Lowe
Dominion
Additional Member Additional Organization Region Segment Selection
1.
Louis Slade
Dominion
RFC
2.
Mike Garton
Dominion
NPCC 5, 6
3.
Randi Heise
Dominion
MRO
6
4.
Michael Crowley
Dominion
SERC
1, 3, 5, 6
6.
Group
Brent Ingebrigtson
Additional Member
3, 5, 6
PPL NERC Registered Affiliates
Additional Organization
Region Segment Selection
1. Brenda Truhe
PPL Electric Utilities Corporation
RFC
1
2. Annette Bannon
PPL Generation, LLC on behalf of Supply NERC Registered Affiliates RFC
5
3.
WECC 5
4. Elizabeth Davis
PPL Energy Plus, LLC
MRO
6
5.
NPCC 6
6.
SERC
6
7.
SPP
6
8.
RFC
6
9.
WECC 6
7.
Group
paul haase
seattle city light
X
X
X
Additional Member Additional Organization Region Segment Selection
1. pawel krupa
seattle city light
WECC 1
2. dana wheelock
seattle city light
WECC 3
3. hao li
seattle city light
WECC 4
4. mike haynes
seattle city light
WECC 5
5. dennis sismaet
seattle city light
WECC 6
8.
Group
Guy Zito
Additional Member
1.
Alan Adamson
X
Northeast Power Coordinating Council
Additional Organization
New York State Reliability Council, LLC
Region Segment Selection
NPCC 10
Consideration of Comments: Project 2013-03 | August 30, 2013
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman
ISO - New England
NPCC 2
8.
Michael Jones
National Grid
NPCC 1
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Christina Koncz
PSEG Power LLC
NPCC 5
11. Helen Lainis
Independent Electricity System Operator
NPCC 2
12. Michael Lombardi
Northeast Power Coordinating Council
NPCC 10
13. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
14. Bruce Metruck
New York Power Authority
NPCC 6
15. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
20. Brian Robinson
Utility Services
NPCC 8
21. Brian Shanahan
National Grid
NPCC 1
22. Wayne Sipperly
New York Power Authority
NPCC 5
23. Donald Weaver
New Brunswick System Operator
NPCC 2
24. Ben Wu
Orange and Rockland Utilities
NPCC 1
25. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
26. Mark Kenny
Northeast Utilities
9.
Dennis Chastain
Group
2
3
4
5
6
NPCC 1
Tennessee Valley Authority
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. DeWayne Scott
SERC
1
2. Ian Grant
SERC
3
3. David Thompson
SERC
5
4. Marjorie Parsons
SERC
6
5. Gary Kobet
SERC
1
Consideration of Comments: Project 2013-03 | August 30, 2013
8
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10.
Group
Terri Pyle
Oklahoma Gas & Electric
2
3
X
X
X
X
4
5
6
X
X
X
X
7
8
Additional Member Additional Organization Region Segment Selection
1. Terri Pyle
OG&E
SPP
1
2. Don Hargrove
OG&E
SPP
3
3. Leo Staples
OG&E
SPP
5
4. Jerry Nottnagel
OG&E
SPP
6
11.
Group
Frank Gaffney
Florida Municipal Power Agency
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
FRCC
3
7. Stanley Rzad
Keys Energy Services
FRCC
3
12.
Group
Terry Volkmann
Additional Member Additional Organization
Region
Segment Selection
1. Gale Nordling
Emprimus
NA - Not Applicable NA
2. Fred Faxvog
Emprimus
NA - Not Applicable NA
13.
Group
X
Emprimus LLC and Volkmann Consulting
Doug Hohlbaugh
FirstEnergy
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Bill Smith
RBB Vote - Seg 1
RFC
1
2.
Cindy Stewart
RBB Vote - Seg 3
RFC
3
3.
Doug Hohlbaugh
RBB Vote - Seg 4
RFC
4
4.
Ken Dresner
RBB Vote - Seg 5
RFC
5
5.
Kevin Querry
RBB Vote - Seg 6
RFC
6
6.
John Reed
FE
RFC
1
7.
Chris Pilch
FE
RFC
1
8.
Mike Miller
FE
RFC
1
9.
Marissa McLean
FE
RFC
1
FE
RFC
1, 3, 4, 5, 6
10. Larry Raczkowski
Consideration of Comments: Project 2013-03 | August 30, 2013
9
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14.
Group
Denise Lietz
2
X
Puget Sound Energy
3
4
X
5
6
X
Additional Member Additional Organization Region Segment Selection
1. Erin Apperson
Puget Sound Energy
WECC 3
2. Lynda Kupfer
Puget Sound Energy
WECC 5
15.
Group
Jason Marshall
Additional Member
Additional Organization
Region Segment Selection
1. Scott Brame
North Carolina Electric Membership Corporation SERC
2. Shari Heino
Brazos Electric Power Cooperative
ERCOT 1, 5
3. John Shaver
Arizona Electric Power Cooperative
WECC 4, 5
4. John Shaver
Southwest Transmission Cooperative
WECC 1
5. Mark Ringhausen
Old Dominion Electric Cooperative
SERC
3, 4
6. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
7. Paul Jackson
Buckeye Power
RFC
3, 4
8. Bill Hutchision
Southern Illinois Power Cooperative
SERC
1
9. Caleb Muckala
Western Farmers Electric Cooperative
SPP
1, 5
16.
Group
Kathleen Black
Additional Member
Additional Organization
X
NERC Training & Standards Development RFC
4
NERC Compliance
RFC
3
3. Al Eizans
Merchant Operations
RFC
5
4. Barbara Holland
SOC
RFC
Robert Rhodes
Additional Member
Additional Organization
X
X
Region Segment Selection
2. Kent Kujala
Group
1, 3, 4, 5
DTE Electric
1. Daniel Herring
17.
X
ACES Standards Collaborators
SPP Standards Review Group
X
Region Segment Selection
1.
John Allen
City Utilities of Springfield
SPP
1, 4
2.
Michelle Corley
Cleco Power
SPP
1, 3, 5
3.
Louis Guidry
Cleco Power
SPP
1, 3, 5
4.
Bo Jones
Westar Energy
SPP
1, 3, 5, 6
5.
Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
6.
Beverly Laios
American Electric Power
SPP
1, 3, 5
7.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
8.
James Nail
City of Independence, MO
SPP
3
Consideration of Comments: Project 2013-03 | August 30, 2013
10
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Mahmood Safi
Omaha Public Power District MRO
1, 3, 5
10. Dennis Sauriol
American Electric Power
1, 3, 5
18.
Jamison Dye
Group
SPP
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Ran Xu
Technical Operations
WECC 1
2. Dan Goodrich
Technical Operations
WECC 1
3. James Burns
Technical Operations
WECC 1
4. Richard Becker
Substation Engineering
WECC 1
5. Don Watkins
System Operations
WECC 1
19.
Group
Tom McElhinney
JEA
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
JEA
FRCC
1
2. Garry Baker
JEA
FRCC
5
3. John Babik
JEA
FRCC
3
20.
Group
S. Tom Abrams
Santee Cooper
Additional Member Additional Organization Region Segment Selection
1. Rene Free
Santee Cooper
SERC
1, 3, 5, 6
2. Chris Wagner
Santee Cooper
SERC
1, 3, 5, 6
3. Tom Abrams
Santee Cooper
SERC
1, 3, 5, 6
21.
Group
David Dockery
Additional Member
Associated Electric Cooperative, Inc. JRO00088
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
22.
Group
Pablo Onate
El Paso Electric Company
Additional Member Additional Organization Region Segment Selection
Consideration of Comments: Project 2013-03 | August 30, 2013
11
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1. Gustavo Estrada
El Paso Electric Company WECC 5
2. Tracy Van Slyke
El Paso Electric Company WECC 3
3. Luis Rodriguez
El Paso Electric Company WECC 6
4. Pablo Onate
El Paso Electric Company WECC 1
23.
2
3
4
5
6
X
X
X
X
Individual
Janet Smith, Regulatory
Affairs Supervisor
24.
Individual
Bob Steiger
X
X
X
X
25.
Individual
Lloyd A. Linke
X
26.
Individual
Steve Rueckert
27.
Individual
Wayne Johnson
X
X
X
X
Individual
29. Individual
Ryan Millard
Steve Lancaster
X
X
X
X
X
X
30.
Individual
Erika Doot
31.
Individual
Kaleb Brimhall
X
X
32.
Individual
William R. Harris
33.
Individual
Paul Rocha
CenterPoint Energy
34.
Individual
John Falsey
Invenergy LLC
35.
Individual
Thomas Foltz
American Electric Power
X
X
X
36.
Individual
John Bee
Exelon and its Affiliates
X
X
X
37.
Individual
Manitoba Hydro
X
X
X
X
X
X
X
X
Individual
Nazra Gladu
Joe O'Brien for Ed
Mackowicz
39.
Individual
Steve Hill
Northern California Power Agency
X
X
40.
Individual
Melissa Kurtz
US Army Corps of Engineers
41.
Individual
Andrew Z. Pusztai
American Transmission Company
X
42.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
43.
Individual
Michael Falvo
Independent Electricity System Operator
28.
38.
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
NIPSCO
Consideration of Comments: Project 2013-03 | August 30, 2013
X
X
X
12
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
44.
Individual
Anthony Jablonski
ReliabilityFirst
45.
Individual
Martyn Turner
X
X
X
X
X
X
X
X
X
X
Individual
47. Individual
Michiko Sell
Ben Li
LCRA Transmission Services Corp
Public Utility District No. 2 of Grant County,
WA
Ben Li Associates
48.
Individual
Don Schmit
Nebraska Public Power District
49.
Individual
Silvia Parada Mitchell
NextEra Energy
Tri-State Generation and Transmission
Association, Inc.
46.
50.
51.
Individual
Sergio Banuelos
Individual
Jack Stamper
X
X
X
X
X
X
X
X
X
Kenn Backholm
53.
Individual
Rich Salgo
NV Energy
X
54.
Individual
Jen Fiegel
Oncor Electric Delivery Complany LLC
X
55.
Individual
Oliver Burke
Entergy Services, Inc.
X
56.
Individual
Dan Inman
Minnkota Power Cooperative, INC.
X
X
X
57.
Individual
Terry Baker
PRPA
X
X
X
58.
Individual
Andrew Gallo
City of Austin dba Austin Energy
X
X
59.
Individual
Texas Reliability Entity
Texas Reliability Entity
60.
Individual
David Jendras
Ameren
61.
Individual
Catherine Wesley
PJM Interconnection, L.L.C.
62.
Individual
Michael Lowman
Duke Energy
Individual
64. Individual
Michael Brytowski
Wryan Feil
65.
Phil Anderson
Individual
66.
Individual
Patricia Metro
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Great River Energy
Northeast Utilities
X
X
X
X
Idaho Power Company
National Rural Electric Cooperative
Association (NRECA)
X
Consideration of Comments: Project 2013-03 | August 30, 2013
8
X
Individual
63.
7
X
Clark Public Utilities
Public Utility District No.1 of Snohomish
County
52.
6
X
X
X
X
X
X
13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
67.
Individual
3
4
5
6
X
Bill Fowler
City of Tallahassee
Individual
69. Individual
Scott Langston
Karen Webb
City of Tallahassee
City of Tallahassee - Electric Utility
70.
Individual
Bret Galbraith
Individual
David Gordon
Seminole Electric
Massachusetts Municipal Wholesale Electric
Company
72.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
73.
Individual
Bryan Griess
Transmission Agency of Northern California
X
74.
Individual
Cheryl Moseley
Individual
Mauricio Guardado
Electric Reliability Council of Texas, Inc.
Los Angeles Department of Water and
Power
76.
Individual
Alice Ireland
77.
Individual
78.
68.
2
X
X
X
X
X
X
X
X
X
X
X
Xcel Energy
X
X
X
X
Angela P Gaines
Portland General Electric Co
X
X
X
X
Individual
Rhonda Bryant
El Paso Electric Company
X
X
X
X
79.
Individual
Joe Tarantino
Sacramento Municipal Utility District
X
X
X
X
X
80.
Individual
Laurie Williams
PNM Resources
X
X
X
X
81.
Individual
Nathan Mitchell
American Public Power Association
X
82.
Individual
Linda Jacobson-Quinn
Farmington Electric Utility System
X
83.
Individual
Rick Terrill
Luminant Generation
84.
Individual
Scott Berry
Individual
Mauricio Guardado
Indiana Municipal Power Agency
Los Angeles Department of Water and
Power
71.
75.
85.
Consideration of Comments: Project 2013-03 | August 30, 2013
X
X
X
X
X
X
X
X
X
X
14
7
8
9
10
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Organization
Supporting Comments of “Entity Name”
Massachusetts Municipal Wholesale Electric
Company
American Public Power Association (APPA)
Western Electricity Coordinating Council
Florida Municipal Power Agency
PRPA
Florida Power & Light
Beaches Energy Services
FMPA
Indiana Municipal Power Agency
IMPA supports the comments submitted by Frank Gaffney from Florida Municipal
Power Agency.
US Army Corps of Engineers
MRO NSRF
Associated Electric Cooperative, Inc. JRO00088
NRECASERC
Portland General Electric Co
PGE supports WECC's position regarding the standard as it relates to the
implementation timeframes.
PPL NERC Registered Affiliates
SERC OC Review Group
Tennessee Valley Authority
SERC OC Review Group
South Carolina Electric and Gas
SERC OC Review Group
Consideration of Comments: Project 2013-03 | August 30, 2013
15
Organization
Supporting Comments of “Entity Name”
Clark Public Utilities
Snohomish County Public Utility District
Nebraska Public Power District
Southwest Power Pool (SPP)
PNM Resources
WECC Staff
Consideration of Comments: Project 2013-03 | August 30, 2013
16
1. The SDT is proposing that the draft stage 1 Standard should apply to Reliability Coordinators, Balancing Authorities with a
Balancing Authority Area that includes any transformer with high side terminal voltage greater than 200 kV, and Transmission
Operator with a Transmission Operator Area that includes any transformer with high side terminal voltage greater than 200 kV.
Do you agree that the SDT has correctly identified the applicable functional entities in the initial draft stage 1 Standard? If you do
not agree, or you agree in general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on the applicability section of EOP-010-1. All comments have
been reviewed and the revised version of EOP-010-1 includes changes that the drafting team considers appropriate. The drafting
team maintains that Generator Operators should not be an applicable entity in the Stage 1 standard and has removed the Balancing
Authority from the applicability as well. All functional entities listed in the Reliability Functions section of the Standards
Authorization Request may still be considered for applicability of Stage 2 standards. The drafting team has clarified that the
applicable Transmission Operators are those with a Transmission Operator Area that includes a power transformer with a high side
wye-grounded winding with terminal voltage greater than 200 kV. The drafting team emphasizes that this applicability statement
describes the functional entity in terms of the assets that they operate, and does not define equipment to be protected by the
Operating Procedures. Additional technical details are available on the Project 2013-03 Project Page. A summary of comments and
the drafting team's response is provided:
Applicability to Generator Operators. Commenters stated that that EOP-010-1 needed to include Generator Operators in
order to require Generator Operators to develop procedures to protect or mitigate the effects of GMD on Generator Step-up
transformers (GSUs). To effectively assess the effects of GMD on a GSU and develop appropriate mitigating Operating
Procedures, a Generator Owner and/or Generator Operator would require a GSU transformer study to determine the impact of
Geomagnetically-induced Current (GIC) (GIC/thermal rating study) and equipment to monitor GIC at the high-voltage wye
winding neutral. Requirements for studies and possible equipment for mitigation is beyond the scope for stage 1. Generator
Owners and Generator Operators are appropriately included in the GMD Standards Authorization Request and will be
considered for inclusion in Phase 2 standards, which will require applicable entities to conduct vulnerability assessments and
develop appropriate mitigation strategies. The drafting team recognizes that some GO/GOPs already have GMD Operating
Procedures for their equipment based on prior studies and/or monitoring equipment. EOP-010-1 will not prohibit or interfere
with a GOP's established procedure. Furthermore, The RC and TOP will be preparing a GMD Operating Plan and Operating
Procedures respectively. Those procedures will address steps that each will be taking to address GMD impacts, which may
include requiring one or more GOPs to take action. Existing standards provide obligations for the GOP to execute actions when
requested by the TOP or RC (refer to TOP-001-2 and IRO-001-3), to prevent or mitigate identified emergencies. Additional
Consideration of Comments: Project 2013-03 | August 30, 2013
17
technical justification for excluding GOPs and BAs from applicability in the stage 1 standard is provided in a supporting white
paper posted on the project page.
Applicability to Balancing Authority. Commenters stated that the BA should be removed from applicability of the standard
because the purpose and scope did not align with the BA functions in the NERC functional model. The drafting team agrees
with removing BAs from the applicability. BAs are responsible for the real time balancing of the system. In order to carry out
that responsibility, BAs will dispatch generation, use regulation and other ancillary services, to keep Area Control Error (ACE)
within reasonable limits while maintaining system frequency. BAs will work with the Transmission Operator (TOP) to adjust
voltage schedules or redispatch generation at the request of the TOP to ensure that the transmission system is operated within
thermal, voltage, and stability limits. The BA would not be expected to initiate specific mitigating actions during a GMD event
and would instead respond to the direction of the TOP and RC. For example, if redispatch of generation or adjustment of voltage
schedules were needed, the BA would not take those actions without a request and, at least, the concurrence of the TOP and/or
RC. Additional technical justification for excluding GOPs and BAs from applicability in the stage 1 standard is provided in a
supporting white paper posted on the project page.
Applicability to all networks greater than 200 kV with grounded-wye transformers. Commenters requested justification for
this threshold, stated that the threshold was lower than necessary, or stated that the threshold was higher than should be
allowed for reliability. The drafting team has prepared a technical justification for establishing a 200 kV threshold in the
applicability of EOP-010-1 and posted it to the project page. Because transmission line resistance decreases by a factor of 10
from 69 kV to 765 kV and lower voltage lines tend to be shorter (for example 115 kV lines are typically less than 15 miles in
average length), the resulting GIC generated by lines rated less than 200 kV are significantly less than those of higher voltages.
Lines with voltage ratings less than 200 kV do not contribute a significant portion of GIC that result in half-cycle saturation of
power transformers, and are typically ignored in system impact studies. Using a voltage higher than 200 kV, such as 345 kV, for a
lower-bound threshold could potentially create a reliability gap in many systems by excluding from the reliability standard a
portion of the network that can be affected by GMD. Results of sensitivity analysis shows that the GIC contribution from the 230
kV portion of the network can result in system impacts during a GMD event. Therefore, establishing 200 kV as the lower-bound
threshold is consistent with operating experience and modeling guidance provided in the literature. Refer to the project page for
a supporting white paper containing further analysis on this topic.
Relationship to the Bulk Electric System definition. Commenters wanted clarification about applicability to non-BES elements,
or recommended language to specifically exclude non-BES elements. The drafting team believes EOP-010-1 should apply to
Reliability Coordinators and all Transmission Operators with a Transmission Operator Area that includes a power transformer
with a high side wye-grounded winding with terminal voltage greater than 200 kV. Regardless of BES definition, the >200 kV
network can experience GMD impacts and needs to be included for the reliable operation of the Bulk-Power System as directed
Consideration of Comments: Project 2013-03 | August 30, 2013
18
in FERC Order No. 779. There is no requirement within EOP-010-1 for Transmission Operators to include or exclude specific
transformers in their Operating Procedures.
Regional applicability. Commenters stated that entities in regions with lower risk or lacking historical evidence of GMD
impacts should be excluded. Stage 1 of FERC Order No. 779 is interpreted to apply to all regions. The proposed standard does
not specify prescriptive measures and allows for each entity to consider entity-specific factors in developing their procedures or
processes. Order No. 779 at P 29 directs NERC to “submit for approval one or more Reliability Standards that require owners and
operators of the Bulk-Power System to develop and implement operational procedures to mitigate the effects of GMDs…”
(emphasis added).
Organization
ACES Standards
Collaborators
Yes or No
No
Question 1 Comment
(1) We recommend the drafting team provide technical justification for choosing 200 kV as the
threshold. We ask that the drafting team consider increasing the voltage level on the high side
of the transformer to 345 kV, or in the alternative, provide rationale for setting the limit at 200
kV.(2) We do not believe the science of how GMDs impact the electric grid is settled. This is
evidenced by multiple reports with significantly varying conclusions. While the FERC order
indicated that most reports agree that there is a minimum risk for voltage collapse due to
excessive reactive power consumption of transformers during extremen GMD events, the
reports may not emphasize the geographic risk of the problem. For example, does a utility in
South Florida have the same risk as a utility in northern Maine? If the risks are different, a
requirement for an operating procedure for all entities including the southern most entities is
premature at this point. We understand that NERC has an obligation to respond to the FERC
GMD directive and will support them in their efforts, however, we wonder if NERC should look
for an equally efficient and effective alternative. We believe that such an alternative should
include pointing to the existing and proposed standards requirements that require registered
entities to respond to voltage emergencies. (3) Given the unsettled GMD science, we think it is
premature to write a standard requiring specific GMD operating plans and procedures and may
cause considerable overlap and redundancy within the standards which the P81 project was
intended to remove and which FERC has already proposed to approve. For example, TOP-001-1a
Consideration of Comments: Project 2013-03 | August 30, 2013
19
Organization
Yes or No
Question 1 Comment
R2 and R8 already requires the TOP to take immediate actions to alleviate operating
emergencies and to restore reactive power balance. TOP-002-2.1b R8 requires the TOP to plan
to meet voltage and/or reactive limits, including the deliverability/capability for any single
Contingency. TOP-004-2 R6.1 requires the TOP to have policies and procedures for monitoring
and controlling voltage levels and reactive power flows. Finally, EOP-001-2 R2.2 requires the
TOP to “develop, maintain, and implement a set of plans to mitigate operating emergencies on
the transmission system”. These standards requirements are applicable at all times including
during GMD events. Thus, the proposed requirements will create an opportunity for double
jeopardy due to the redundancy in the requirements. (4) The Balancing Authority (BA) should
not be listed as an applicable entity in the standard. Per the NERC functional model, the BA is
focused on balancing load, interchange and generation and supporting system frequency while
the Transmission Operator (TOP) is focused transmission flows and, in particular, controlling
voltages. The background section is focused on preventing transformer hot spot heating and
voltage collapse through excessive use of reactive power which clearly aligns with the TOP tasks
and not the BA tasks in the NERC functional model. While the BA might have a role if additional
generation is committed, the role would be, in essence, to respond to TOP actions. It would be
the TOP that would identify the need to commit additional generation to mitigate loading on
transformers or to increase reactive support. The BA would commit generation in response to
the TOP directions and would utilize existing operating procedures and processes it has for
managing commitment of units. Its existing procedures and processes, for example, might
include a minimum generation procedure. Implementing the procedure in response to excess
generation that needs to be committed to respond to a GOP event would be no different than
responding when load has simply decreased below the normal minimum generation limits. Thus,
there is no need to add the BA because its existing procedures and processes would be sufficient
to respond to the TOP actions.
Sacramento
Municipal Utility
District
No
~1. The applicability ought to be clear that the standard refers to only BES transformers and not
step-down transformers to distribution.~2. Referring to the Oak Ridge national Laboratory 319
report, the winding(s) in question needs to be wye connected and not delta connected for
ground current to flow. The geomagnetically induced current (GIC) is ground current. Hence, the
applicability ought to specify transformers with "wye" connected winding(s) above a certain
Consideration of Comments: Project 2013-03 | August 30, 2013
20
Organization
Yes or No
Question 1 Comment
threshold voltage. Three phase core transformers are much less likely to saturate and result in
MVAR demands about 25% of that of three single core transformers. Hence, the applicability for
> 200 kV and < 400 kV (i.e., the 230 and 345 kV transformers) ought to be limited to single phase
core transformers.
Colorado Springs
Utilities
No
o GOP should also be included. o Voltage level not a good indicator of susceptibility to ground
induced currents. Possibly latitude, transmission line orientation or transmission line length a
better indicator. If voltage were to be used, think higher voltage should be considered.
American Public
Power
Association
No
APPA appreciates the SDT’s effort to limit the applicability of the proposed standard by setting a
voltage threshold for TOPs and BAs. On the July 30th webinar the SDT stated that a technical
whitepaper was being developed to justify the 200 kV threshold. APPA will hold any comments
on the voltage threshold until after the whitepaper is released. We request that the whitepaper
be provided soon so the industry has time to discuss this threshold prior to the final comment
and ballot period.APPA recommends that the SDT modify the applicability section wording to
replace “transformers” with “BES transformers.” Including only BES transformers will make the
applicability of the standard clear. Some Transmission Owners may have transformers with high
side voltage above 200 kV, but they are connected radially so are not part of the BES. These
transformers should be out of scope for this standard.
Minnkota Power
Cooperative, INC.
No
Do not agree with the statement "includes any transformer with high side terminal voltage
greater than 200kV". This would include potiential transformers with high side terminal voltage
greater than 200 kV and smaller, high impedance non-BES transformers serving load. We believe
that the effects of GMD on these devices are significantly reduced because of the high
impedance of these systems.Applicability should be changed to "includes power transformers
with the high side terminal voltage greater than 200kV and a base rating of at least XX MVA".
The change from "any transformer" to "power transformer" will match the 2012 GMD Report,
Chapter 5 - Power Transformers. The addition of “XX MVA” will limit the inclusion of small 200+
kV connected transformers. It is unclear as to what that limit should be and the evidence for that
limit is unknown. Alternatively, could make the statement “includes BES power transformers
with a high side terminal voltage greater than 200 kV” but this could exclude large load serving
Consideration of Comments: Project 2013-03 | August 30, 2013
21
Organization
Yes or No
Question 1 Comment
transformers that do have a significant effect in relation to GMD events.
MRO NERC
Standards Review
Forum (NSRF)
No
Do not agree with the statement "includes any transformer with high side terminal voltage
greater than 200kV". This would include potiential transformers with high side terminal voltage
greater than 200 kV. We believe that the effects of GMD on these devices are significantly
reduced because of the high impedance of these systems.Applicability should be changed to
"includes power transformers with the high side terminal voltage greater than 200kV". The
change from "any transformer" to "power transformer" will match the 2012 GMD Report,
Chapter 5 - Power Transformers.
Florida Municipal
Power Agency
No
FMPA appreciates the efforts of the SDT and, in general, we believe the standard is good.
However, we believe the Applicability of the standard needs improvement; and that is the
primary reason we are voting Negative.The ORNL report, which FMPA believes is already
unreasonably pessimistic, made several conclusions that are not reflected in the applicability
that FMPA believes ought to be:1. The applicability ought to be clear that the standard refers to
only BES transformers and not step-down trasformers to distribution.2. The winding(s) in
question needs to be grounded wye connected and not delta connected for ground current to
flow. The geomagnetically induced current (GIC) is ground current. Hence, the applicability ought
to specify transformers with grounded wye connected winding(s) above a certain threshold
voltage3. According the the ORNL 319 report
(http://web.ornl.gov/sci/ees/etsd/pes/pubs/ferc_Meta-R-319.pdf, Figure 1-17), 3 phase / 3 leg
core design transformers are much less likely to saturate and result in MVAR demands about
25% of that of three single phase transformers. Hence, the applicability for > 200 kV and < 400
kV (i.e., the 230 and 345 kV transformers) ought to be limited to single phase transformers.4.
The primary concerns for GIC is for voltage collapse or relay misoperation due to increased
MVAR demand of transformers that could potentially result in cascading, and potential damage
to transformers (see SAR description of Industry Need); hence, the applicability should not be to
BAs but only RCs and TOPs (see additional discussion in response to question 3).5. FMPA also
believes that the 200 kV threshold ought to be raised to 300 kV. Almost all 230 kV transformers
are 3 phase / 3 leg core transformers with a much lower probability of becoming saturated;
whereas, according to ORNL, about 15% of 345 kV transformers are single phase transformers
Consideration of Comments: Project 2013-03 | August 30, 2013
22
Organization
Yes or No
Question 1 Comment
(Figure 1-19). In addition, the resistance ot 230 kV lines is significantly higher than 345 kV lines,
which will significantly reduce GIC (see Figure 1-12 noting that the chart is semi-logarithmic) for
lines of similar length (see figure 1-14). This is largely due to the fact that most 345 kV lines are
two conductor bundles for RFI purposes and most 230 kV lines are single conductor; hence, 230
kV lines are roughly twice the resistance of 345 kV lines for the same length of line.FMPA
assumes that GSU’s owned by the GO and operated by the GOP is intended to be included in the
applicability (since the vast majority of GSU’s are grounded wye connected on the high side), but
under the interconnecting TOP’s operating plan. However, the applicability does not reflect this.
If the intent of the SDT is to include these GSUs, then the applicability ought to be changed
accordingly. As such, FMPA suggests the following for applicability:4.1. Functional Entities:4.1.1
Reliability Coordinator4.1.3 Transmission Operator with a:4.1.3.1 Transmission Operator Area
that includes any BES transformer with three single phase transformers connected in a grounded
wye configuration of 300 kV or greater; or4.1.3.2 Transmission Operator Area that includes any
BES transformer with at least one grounded wye connected winding greater than 400 kV (either
three single phase transformers or a three phase transformer); or4.1.3.3 Transmission Operator
Area that interconnects with any generator interconnection facilities that include a GSU that
meets either criteria 4.1.3.1 or 4.1.3.2
Idaho Power
Company
No
For stage 1, operational procedures make sense for Transmission Operations and not necessarily
for Generation Operations. However, generator step-up transformers (GSUs) with a grounded
wye high side can be affected by geomagnetic induced current (GIC). If the GSU is the property
of and/or controlled by a generator operator, transformer information such as GIC, temperature,
dissolved gas and abnormal operation may not be easily monitored by the Transmission
Operator. Any operational changes made by the Generator Operator will need to be coordinated
by the Transmission Operator but the Transmission Operator may not be aware of GSU status.
While System wide GMD operating procedures do not apply to Generator Operators, equipment
level situational awareness and monitoring might. Idaho Power believes this standard should
also apply to Generator Operators. Propose adding Generation Operator with any transformer
with a high side terminal voltage greater than 200 kV to the Applicability Functional Entities
Section 4.
Consideration of Comments: Project 2013-03 | August 30, 2013
23
Organization
Yes or No
Question 1 Comment
PacifiCorp
No
Generator Operators are listed as applicable functions within the SAR but are absent from the
scope of applicability of EOP-010-1. If Generator Operators are not included under the standard
they should be removed from the scope of the SAR, as this creates inherent confusion as to their
explicit applicability to the standard. Additionally, PacifiCorp does not support inclusion of the
BA as an applicable functional entity.
Great River
Energy
No
GRE agrees with ACES recommending the drafting team provide technical justification for
choosing 200 kV as the threshold. We ask that the drafting team consider increasing the voltage
level on the high side of the transformer to 345 kV, or in the alternative, provide rationale for
setting the limit at 200 kV.GRE agrees with ACES and does not believe that the Balancing
Authority (BA) should be listed as an applicable entity in the GMD standard. Per the NERC
functional model, the BA is focused on balancing load, interchange and generation and
supporting system frequency while the Transmission Operator (TOP) is focused transmission
flows and, in particular, controlling voltages. It would be the TOP or RC that would identify the
need to commit additional generation to mitigate loading on transformers or to increase reactive
support.
Los Angeles
Department of
Water and Power
No
LADWP is making a correction to Question 1 and therefore is resubmitting its comments from
yesterday. Please take these comments and regard the ones from
yesterday.______________________________________________________________________
_____________________________Reliable operation of the BES requires that GMD be
responded to by all parties with equipment electrically connected to the interconnection. The
NERC 2012 Special Reliability Assessment Interim report: Effects of Geomagnetic Disturbances
(GMDs) on the Bulk Power System” proposes the steps outlined below for development of
effective mitigation of GMDs, based on the fact that measures taken piece meal by one or more
stakeholders (as opposed to those based on engineering studies and operation of the
interconnection as a whole) will shift, and may concentrate, Geomagnetically Induced Currents
(GICs) causing damage and possibly uncontrolled separation, or cascading failure of other system
elements. Phase One - Assess and Baseline RiskPhase Two - Perform Technical and
Programmatic AnalysisPhase Three - Develop Integrated SolutionsPhase Four - Implement
Consideration of Comments: Project 2013-03 | August 30, 2013
24
Organization
Yes or No
Question 1 Comment
Solutions and Adjust System ProceduresIt seems that EOP-010 is bringing requirements for
operational procedures to mitigate GMDs before the relevant studies are complete, and then
update them periodically as data improves. To this end NERC has developed the “Geomagnetic
Disturbance Operating Procedure Template” for Transmission Operators, which suggests a run
back on equipment limits to leave headroom for the GICs.Given the above, and the fact that
Generator Step Up (GSU) transformer (primaries >20kV) windings tend to have the highest
currents of any BES transformer, Generator Operators should be included in stage 1 standards
with the recommendation that they also have a mandatory runback to maintain D curve
headroom on the generators (which will probably be called on to meet extra VAR requirements)
and headroom on transformer limits to accommodate GICs.
National Rural
Electric
Cooperative
Association
(NRECA)
No
NRECA recommends increasing the voltage level threshold from 200 kV to 345 kV. The drafting
team has not provided a technical justification for choosing the 200 kV threshold. It appears that
from the limited previous experiences associated with GMD events that there was no
substantive impact on equipment at voltages below 345 kV. In addition, it is important that any
standard that is developed addressed regional geographic differences associated with the
impacts of GMD in the requirements of the standard. Present data does not support that the
potential for equipment damage resulting in a GMD event is the same for a cooperative in the
Northeast and a cooperative in the Southeast. The inclusion of the Balancing Authority as an
applicable entity is not necessary. If the events being addressed in this standard are solely
related to preventing transformer hot spot heating and voltage collapse through excessive use of
reactive power, these types of events are managed by the Transmission Operator not the
Balancing Authority. The Balancing Authority will only provide generation support as directed by
the Transmission Operator.
SPP Standards
Review Group
No
Please refer to our comment in Question 7 directed toward applicability in the SAR.
Pepco Holdings
Inc & Affiliates
No
Recommend adding “BES” as qualifier for transformer.4.1.1 Reliability Coordinator 4.1.2
Balancing Authority with a Balancing Authority Area that includes any BES transformer with high
side terminal voltage greater than 200 kV 4.1.3 Transmission Operator with a Transmission
Consideration of Comments: Project 2013-03 | August 30, 2013
25
Organization
Yes or No
Question 1 Comment
Operator Area that includes any BES transformer with high side terminal voltage greater than
200 kV
Los Angeles
Department of
Water and Power
No
Reliable operation of the BES requires that GMD be responded to by all parties with equipment
electrically connected to the interconnection. The NERC 2012 Special Reliability Assessment
Interim report: Effects of Geomagnetic Disturbances (GMDs) on the Bulk Power System”
proposes the steps outlined below for development of effective mitigation of GMDs, based on
the fact that measures taken piece meal by one or more stakeholders (as opposed to those
based on engineering studies and operation of the interconnection as a whole) will shift, and
may concentrate, Geomagnetically Induced Currents (GICs) causing damage and possibly
uncontrolled separation, or cascading failure of other system elements. Phase One - Assess and
Baseline RiskPhase Two - Perform Technical and Programmatic AnalysisPhase Three - Develop
Integrated SolutionsPhase Four - Implement Solutions and Adjust System ProceduresIt seems
that EOP-010 is bringing requirements for operational procedures to mitigate GMDs before the
relevant studies are complete, and then update them periodically as data improves. To this end
NERC has developed the “Geomagnetic Disturbance Operating Procedure Template” for
Transmission Operators, which suggests a run back on equipment limits to leave headroom for
the GICs.Given the above, and the fact that Generator Step Up (GSU) transformer (primaries
>200kV) windings tend to have the highest currents of any BES transformer, Generator
Operators should be included in stage 1 standards with the recommendation that they also have
a mandatory runback to maintain D curve headroom on the generators (which will probably be
called on to meet extra VAR requirements) and headroom on transformer limits to
accommodate GICs.
seattle city light
No
Seattle City Light supports the general concepts presented in the draft Standard and appreciates
that the Standard Drafting Team affords each entity flexibility as to procedures. However, Seattle
is concerned about the broad applicability of the Standard as proposed, and recommends that it
only apply to BA and TOPs with Bulk Electric System (BES) transformers 200kV and above (as well
as all RCs). This change would make this Standard consistent with other Standards as well as the
BES definition we've worked so hard on the past several years.
Consideration of Comments: Project 2013-03 | August 30, 2013
26
Organization
Yes or No
Question 1 Comment
Western
Electricity
Coordinating
Council
No
See FMPA concerns on aplicability, type of transformer, and whether or not the BA should be an
applicable entity.
Arizona Public
Service Company
No
Should only apply to transformers which are part of BES. BES definition is based upon the low
side winding voltage of greater than 100 kV where as this requirement is based upon high side
voltage. Thus, this goes beyond BES elements. We suggest it apply to transformer with low side
winding voltage of 200 kV or greater.
Public Utility
District No.1 of
Snohomish
County
No
SNPD agrees in general but believes the 200 kV voltage threshold is premature. In general, we
believe that GMD should be tackled on a regional basis and already by the Reliability Coordinator
(“RC”). It is our understanding that location (latitude and local geology) and the type of systems
(i.e., systems with extra-high-voltage, series capacitor compensated lines, transformer
configuration & grounding, and line length) are important elements in a GMD analysis.
Therefore, a one-size-fits-all approach based on voltage level would be inappropriate. SNPD
believes the Reliability Coordinator (“RC”) would be in the best position to identify facilities
including the appropriate voltage level or other attributes that may become more apparent as
research in this area matures.
Foundation for
Resilient Societies
No
Standards relating to Operating Procedures should apply to high side Transformers of 100 kV or
higher. Despite higher resistance, transformers in the 100 kV to 200 kV range contribute a
significant proportion of GICs that can destabilize the grid. TJ Overbye et al (2012)estimate less
than 60% of total MVAR is captured in New England and Michigan if transmission under 230 kV is
excluded from protection. New transformers in the 100 kV to 200 kV range are projected by the
Energy Information Administration at about 20% of all new EHV transmission mileage planned
for the 2012-2018 period. NERC must include generating entities, because existing studies suffice
to demonstrate both vulnerability of GSU transformers operated by Generating entities and
need for equipment monitoring at generator stators, and related operating procedures to
protect generators in severe geomagnetic storms. GSU Generators are at greater risk than
generally recognized. See studies by Legro, Abi-Samra and Tesche at ORNL (1985); Walling &
Consideration of Comments: Project 2013-03 | August 30, 2013
27
Organization
Yes or No
Question 1 Comment
Kahn (1991); J G Kappenman, Storm Analysis Report R-112, section 8 (2011); and Luis Marti,
"Generator Thermal Stress during a Geomagnetic Disturbance" (2013). Of critical importance,
the President of the United States has existing legal authority to order the de-energizing of
electric generating facilities that are oil or gas-fired if an emergency so requires. To utilize this
authority upon confirmed space warning of a severe solar geomagnetic storm, it is essential that
all generating entities serving the bulk power system be included in emergency operating
procedure standards; their personnel be trained to validate and confirm de-energizing orders
and procedures (and re-energizing procedures), with a multi-day strategic warning but only tens
of minutes for tactical order, validation, and execution. Because most of the generating
facilities serving the bulk power system are not now equipped with protective equipment that
would enable these facilities to "operate through" a severe solar geomagnetic storm, it is
essential that generating entities be included in the Operating Procedure coverage and
standards. Further, the Nuclear Regulatory Commission has existing authority to order deenergizing and safe shutdown of the 102 NRC licensed nuclear power plants in the U.S. or a
subset that are especially affected by a particular GMD event. Generating entities may need to
review operating procedure options for rapid shutdown of generators if GSU transformers are
not equipped with protective hardware. Beyond the practical necessity of including
transformers and transmission equipment in the 100 kV to 200 kV range, FERC Order 779 applies
to the entire bulk power system, which is now defined as commencing at 100 kV or above and
not 200 kV or above. It would be illegal for NERC to exclude a significant proportion of the
transmission line mileage (for many utilities more than half total EHV transmission mileage).
Even if EHV transformers above 200 kV are later protected with neutral ground blocking
equipment, leakage of GICs from lower voltage equipment will add significant Mvar into regional
grids. FERC intended standards to protect the entire bulk power system of 100 kV or higher;
NERC's participating entities should respect and support this federal policy.
DTE Electric
No
System study of areas potentially affected by GMDs should be identified before standard is
written requiring all entities to have plans and operating procedures.
JEA
No
The applicable entities should’t not include the BA but needs to include the GOs. Generator step
up transformers are more critical to BES reliability than substation step down transformers. Only
Consideration of Comments: Project 2013-03 | August 30, 2013
28
Organization
Yes or No
Question 1 Comment
BES transformers should be included.
Oncor Electric
Delivery
Complany LLC
No
The draft fails to include Generator Owners and Generator Operators that have step-up and
auxillary transformers with a terminal higher that 200 kV. If GMD causes unintended ground
induced currents (GICs) on Transmission Owners’ and Transmission Operators Transmission
Transformers that are important to the grid, then it stands to reason that step-up and auxillary
transformers are at risk as well. Generator Owners transformers have a great impact to the
reliability of the system. Those transformers need to be included in the Standard. Additionally, it
would seem imperative to include generator owner transformers that supply offsite power to
nuclear generation that are above 200 kV. The Standard must include the GO and GOP in order
to address the FERC Order.
Puget Sound
Energy
No
The drafting team should ensure that the voltage level in the applicability statement does not
include elements excluded by the Bulk Electric System definition. Specifically, it appears that the
applicability statement would include equipment excluded from the BES by the language of BES
Definition Inclusion I1 ("Transformers with the primary terminal and at least one secondary
terminal operated at 100 kV or higher..."). Also, voltage level is not the only measure of GMD
influence on the BES - there are other factors that the standard should include in its assessment
of applicability, including grounding method, grounding resistivity, core type and transformer
(coiled equipment) connections. Leaving these factors out of the applicability section means
that many entities who are unlikely to be affected by a GMD event will be unnecessarily
burdened with drafting procedures that they may never need. In addition, it is not clear why the
Balancing Authority is included as an applicable entity - in general, the actions available to the
operators are transmission system specific. However, if the Balancing Authority is removed as a
responsible entity, the drafting team should ensure that generation interconnection facilities are
also assessed for applicability with respect to the interconnected TOP.
NV Energy
No
The preparation and execution of operating procedures to mitigate the effects of GMD events on
the power system are specific to the Reliability Coordinator and the Transmission Operator
entities. We do not believe that actions are required of the Balancing Authority function at all,
as this is not a balancing issue, but rather a transmission operations issue. Additionally, we
Consideration of Comments: Project 2013-03 | August 30, 2013
29
Organization
Yes or No
Question 1 Comment
believe the scope of applicability should not reach into distribution transformers, particularly
radial transformers serving distribution load. Hence, we recommend that the Applicability
section be modified to remove 4.1.2 (Balancing Authority) and place a limitation on 4.1.3 to
restrict applicability to BES transformers of the indicated voltage range.
LCRA
Transmission
Services Corp
No
The standard has not provided a clear reason for starting at 200 kV, which seems arbitrary.
Papers on GMD do indicate the potential risk to transformer’s increases at the higher voltage
levels and in particular to single phase wye connected transformers. Would propose the
following:4.1.3.1 a Transmission Operator Area that includes any BES transformer with three
single phase core windings connected in a "wye" configuration of 300 kV or greater; or4.1.3.2 a
Transmission Operator Area that includes any BES transformer with at least one "wye"
connected winding greater than 400 kV;
NIPSCO
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC
reaching levels that would harm transformers. There is also historical evidence of the presence
of and correspondingly the absence of GIC in systems. These two factors should be used to
determine if a TOP/BA needs to develop, maintain, and implement Operating Procedures to
mitigate the effects of GMD events on the reliable operation of its respective system. If the
conditions for GIC do not exist and there is no history of GIC induced damage or misoperation, a
RC should not be required to include those TOP/BAs in coordinating plans for GMD other than
to provide assistance as required in other standards.
Oklahoma Gas &
Electric
No
This standard should not be applicable to Balancing Authorities. FERC Order No. 779 directed
the ERO to develop one or more Reliability Standards that require owners and operators of the
BPS to develop and implement operational procedures to mitigate the effects of GMDs. The
functions of the BA center around balancing load and generation and implementing and
accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES
elements such as transformers.
Tri-State
Generation and
No
Tri-State believes that Balancing Authorities should not be included as an applicable entity
because there will be unnecessary duplication or conflict between the BA and the Reliability
Consideration of Comments: Project 2013-03 | August 30, 2013
30
Organization
Yes or No
Transmission
Association, Inc.
Question 1 Comment
Coordinator Operating Plans.
Texas Reliability
Entity
No
We agree with the RC and TOP functions. The SDT may also want to consider adding the GOP
function so that large GSU’s are also monitored under this standard.
CenterPoint
Energy
Yes
CenterPoint Energy agrees in general with the SDT proposal but has an alternative suggestion for
the specific roles of the applicable responsible entities. Please see CenterPoint Energy’s
comments regarding Requirement 1 (Question 2).
City of Austin dba
Austin Energy
Yes
During the July 30, 2013 GMD webinar, the response to one question was that the SDT would
consider whether the BA applicability is appropriate. Austin Energy (AE) would encourage the
SDT to complete that effort.
Northern
California Power
Agency
Yes
For Stage 1 I believe the SDT has it correct; however I am concerned that there is no mention as
to what will happen with IRO-005-3.1a R3 which appplies to a host of registrations. At some
point EOP-010-1 will supercede IRO-005-3.1a, but no mention in the implementation plan is
discussed.
Emprimus LLC
and Volkmann
Consulting
Yes
For the Stage 1 standard, appropriate inclusion of affected transformers is not as important as it
will be in Stage 2. What is important for the Stage 1 standard to capture in its applicability
section the portion of the BES most effected by a GMD and the most influential to maintain BES
reliability. In capturing RC, BA and TOP with 200kv transformers, the SDT has captured entities
that have influence over the 200kv and above system. For entities the own and operate
facilities between 100 and 200kv, their system reliability will be maintained by the RC and any
neighboring / over-arching entities that operation 200kv and above.
Northeast Utilities Yes
I agree with the applicability, however if the definition of BES changes I do not think this
standard should apply down to those with transformers having high sides of 100 kV. The impact
of GMDs and the magnitude of GICs is greatly reduced at these lower voltages and doesn't
warrant the additional burden it would impose.
Consideration of Comments: Project 2013-03 | August 30, 2013
31
Organization
Yes or No
Question 1 Comment
PJM
Interconnection,
L.L.C.
Yes
PJM has also signed onto SERC's comments.
Santee Cooper
Yes
Recommend the SDT consider changing he high side terminal voltage on transformers to greater
than 300 kV. The focus of the standard should be at higher voltages where the line length makes
the lines more vulnerable to geomagnetically-induced currents.
Northeast Power
Coordinating
Council
Yes
The Applicability and Purpose conflict however. The Purpose says “To mitigate the effects of
geomagnetic disturbances (GMD) events by implementing operating procedures.” But the
Standard’s Purpose is not consistent with the Standard. The Standard goes into detail about the
mitigation plans. Recommend the Purpose be “To establish and implement GMD mitigation
operating procedures”. The effectiveness of these procedures to mitigate the effects of GMD is
unknown.
Southern
Company
Yes
The currently drafted standard does not include GOPs as an applicable entity. Consideration
should be made to include them as an entity for reliability purposes. For example, a GOP may
decide to take a unit offline if a K7 is declared, and if so, the reliability entities would need to
know that these units are not available, if needed. In addition, if GOPs are added as applicable
entities, they need to have a requirement to provide their plan to the reliability entities.
Although we are suggesting adding the Generator Operator as an applicable entity, we do
suggest that they be allowed to develop their own GMD Operating Plan or implement the GMD
Operating Plan of its Transmission Operator.We also believe, consistent with our response to
Question #7 below, that the standard should not apply to BAs, as the the risks mitigated by
requiring them to have Operating Procedures are things that the TOP monitors and can either
take action themselves or instruct the BA to redispatch generation.
ReliabilityFirst
Yes
There may be cases in which a transformer with a high side terminal voltage of greater than 200
kV is not considered BES (e.g., the transformer is excluded as part of a local network).
ReliabilityFirst requests clarification whether this non-BES transformer is included within the
Consideration of Comments: Project 2013-03 | August 30, 2013
32
Organization
Yes or No
Question 1 Comment
scope of the standard?
Salt River Project
Yes
We agree that the scope is appropriate.
Entergy Services,
Inc.
Yes
We feel that the focus of this standard should be at the higher voltage such as 345 kV lines
where line length makes the lines more vulnerable to GIC. It is recommended that the SDT
consider changing the high side terminal voltage to greater than 300 kV. One of the reasons for
the change is due to the number of transmission to distribution transformers where the high
side voltage is 230 kV. On the other hand, having the 200 kV cutoff has the potential to create
confusion for BA. A BA with no 200 kV transformers may be intertwined with a TOP that does
have the issue and likely will be exposed to issues that the TOP faces.
Duke Energy
Yes
While Duke Energy agrees in principle with starting at 200kV and above for having a GMD
process/procedure, we believe that 300kV and above would be a more appropriate bright-line.
In addition, if the bright-line remains at 200kV and above, we recommend the SDT should
consider an alternative method of including only 200kV and above BES elements. Lastly, Duke
Energy believes that only transformers with wye connected winding(s) should be included
because only wye connected winding(s) are affected by GIC(s).
SERC OC Review
Group
Yes
Yes. We feel that the focus of this standard should be at the higher voltage such as 345 kV lines
where line length makes the lines more vulnerable to GIC. It is recommended that the SDT
consider changing the high side terminal voltage to greater than 300 kV. In addition, if the
original language (greater than 200kV), remains in the standard, there should be an exception
for equipment such as transformers.
Hydro One
Networks Inc.
Yes
Dominion
Yes
FirstEnergy
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
33
Organization
Yes or No
Bonneville Power
Administration
Yes
Western Area
Power
Administration
Yes
Bureau of
Reclamation
Yes
American Electric
Power
Yes
Exelon and its
Affiliates
Yes
Manitoba Hydro
Yes
American
Transmission
Company
Yes
Independent
Electricity System
Operator
Yes
Question 1 Comment
Public Utility
Yes
District No. 2 of
Grant County, WA
Ben Li Associates
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
34
Organization
Yes or No
Electric Reliability
Council of Texas,
Inc.
Yes
Xcel Energy
Yes
Farmington
Electric Utility
System
Yes
Luminant
Generation
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
Question 1 Comment
35
2. In Requirement R1, the SDT is proposing to require Reliability Coordinators to develop, maintain, and implement a GMD
Operating Plan. This coordinating role for the RC is based on the functional model and addresses the Order No. 779 directive to
consider the coordination of Operating Procedures across regions by a functional entity with a wide-area view. The defined term
"Operating Plan" provides the RC with latitude to determine specific activities necessary to achieve this goal. Do you agree that
the SDT has correctly addressed this directive? If you do not agree that this requirement addresses the directive, or you agree in
general but feel that alternative language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on Requirement R1. The drafting team reviewed all comments
and has incorporated changes into a revised version of EOP-010-1. These changes include rewording part 1.2 and measure M1 to
improve clarity. The drafting team believes the revised version of EOP-010-1 achieves the necessary level of coordination required for
effective planning and real-time operations while at the same time preserving the Transmission Operator's latitude to act based on
system specific or localized conditions. The drafting team has added a new Requirement R2 to the revised version of EOP-010-1 to
maintain the Reliability Coordinator's responsibility for providing space weather forecast information and specified that this
requirement would become effective upon retirement of IRO-005-3.1a Requirement R3. A summary of comments and the drafting
team's response is provided:
Recommendation to replace the word "implement" with "coordinate" in Measure M1, and to clarify what is meant by
'Implement'. Commenters stated that the measure was not consistent with the requirement, and that the additional
information was needed about the SDT's intent. The SDT discussed this suggestion and agreed that the measure and
requirement needed to be improved for consistency. The SDT agrees with the spirit of the comment, and Requirement R1 and
corresponding Measure M1 have been revised to clarify what is intended by “implement”. The SDT considers an operating plan,
process, or procedure to be implemented by carrying out its stated actions. The measure now specifies that operator logs, voice
recordings, or transcripts are the required evidence to show that the stated actions in an Operating Plan, Operating Process, or
Operating Procedure have been carried out.
Recommendation to replace the word "all" with "applicable" in Requirement R1, Part 1.2. Commenters stated that the draft
wording could cause confusion. The SDT agrees with the spirit of the comment and deleted the word 'all'. The SDT believes that
the applicability statement establishes to whom the requirement applies.
Recommendation to add Same Day Operations Time Horizon to Requirement R1. Commenters stated this addition would be
appropriate. Same-day Operations are described as routine actions required within the timeframe of a day, but not real-time.
The SDT agrees with the commenter and has made a revision to the proposed standard.
Recommendation for a longer implementation period. Commenters stated that additional time was needed for coordination
among applicable entities, or for additional studies or information. The SDT is sympathetic to the challenge of completing the
necessary coordination in a 6 month time period, but the 6 month implementation period was suggested in FERC Order No. 779.
The intent of EOP-010-1 is to have applicable registered entities investigate the potential impacts to their system and equipment
to the degree possible and establish reasonable operational steps to be taken to mitigate the impacts with the understanding
that additional research is underway and will provide better information in the future. The SDT believes that some prudent steps
can be taken in the absence of more complete information and that this standard is consistent with the directives in Order No.
779. The SDT anticipates that the process to achieve compliance with EOP-010-1 will require collaboration among the RC and all
entities included in the RC's GMD Operating Plan.
Recommendation to modify the standard to require RCs to develop the Operating Procedures for entities in the Reliability
Coordinator Area, which may be supplemented by optional procedures developed by TOPs. A commenter stated that in areas
with a lower historical risk it is inefficient or ineffective for all TOPs to develop Operating Procedures. A commenter stated
that when historical and physical evidence shows GIC conditions do not exist for a TOP then the RC should not be required to
include them in their coordinating plans. The SDT believes that the requirement to have Operating Procedures must apply to
all applicable TOPs in each RCA. Response to GMD events will vary based on local conditions but a key feature to response is to
ensure that all applicable entities are responding in a coordinated manner within the RC area. The RC's Operating Plan should
provide the necessary level of coordination for efficiency and effectiveness. An RC's Operating Plan may include Operating
Procedures, as defined in the NERC Glossary of Terms.
Comments that Requirement R1 lacks specificity. Some commenters stated that the RC was given too much latitude; some
commenters stated that the RC should be required to establish trigger conditions and a means for verifying compliance within
the RCA. Commentors stated that the wording in R1 and R3 is of a “fill-in-the-blank” nature. The SDT believes that the
variability in the impacts of GMD across the system, based on a number of factors, precludes the ability to develop prescriptive
requirements for GMD response at the RC level. The term “fill-in-the blank” standards refers to standards that require a bulk
power system user, owner, or operator to implement regional criteria that are not specifically part of a NERC Reliability Standard
and is not applicable to EOP-010-1.
Recommendation to reword Requirement R1 so that the RC is responsible to "coordinate the development" of the GMD
Operating Plan. Commenters viewed this as a more appropriate role. The SDT has modified Requirement R1 to address this
concern. The modifications and additional explanatory material are the SDT’s attempt to clarify the dual obligations of the RC to
both coordinate the development of the Operating Plan but also to implement the Operating Plan.
Consideration of Comments: Project 2013-03 | August 30, 2013
37
Clarification of the RC's responsibilities for space weather notifications. The SDT agrees with commenters that supported
requiring the RC to provide GMD forecast information. The drafting team noted that IRO-005-3.1a Requirement R3 currently
provides this obligation. However, NERC Board has approved IRO-005-4 which, would result in retirement of that requirement.
The SDT has added a new Requirement R2 to the draft standard to clearly designate the RC as the entity to disseminate space
weather information to the applicable entities and specified the conditions in the implementation plan for making Requirement
R2 effective upon retirement of IRO-005-3.1a Requirement R3.
Recommendation to use the defined term “Operating Process.” Commenters provided several views including a
recommendation to substitute Operating Process for Operating Plan in Requirement R1, and substitute “Operating Process”
for “Operating Procedure” in R3. The SDT believes that “Operating Plan” is the correct defined term with respect to the
requirement assigned to the RC. However, the term “Operating Process” could apply to the requirement assigned to the TOP, so
the SDT has modified R3 to include Operating Process.
Recommendation to require post-event analysis of GMD response. The SDT agrees that this can be a valuable practice to assess
the effectiveness of the plans and procedures. It does not believe that the practice should be required in the standard. There are
processes at NERC to perform post-event analysis, apart from the standards process. The NERC Events Analysis program
supports the industry’s post-event review and learning needs, and this includes emerging risks. Additionally the GMD Task Force
provides a forum for best practices and learning that can include post-event reporting and analysis from participating entities.
Market concerns during GMD events. A commenter stated that the standard should address suspension of the market during
GMD events. NERC Reliability Standards are market-neutral and neither mandate nor prohibit any specific market structure.
Pursuant to Order No. 693, NERC Reliability Standards should have no undue negative effect on competition and should not limit
use of the Bulk-Power System in an unduly preferential manner. NERC Reliability Standards do not preclude market solutions to
achieving compliance with standards. See the Reliability and Market Interface Principles available here:
http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf.
Clarifications, rewording, and recommendations to enhance coordination. Commenters expressed concerns over the burden
being required of RCs to coordinate Operating Procedures, the perceived limits of their authority to resolve conflicts,
requirements to ensure coordination among RCs, and how to determine that coordination has occurred. The SDT believes that
the RC has sufficient authority to resolve coordination issues with applicable entities related to GMD Operating Plans, Processes
and Procedures in the Reliability Coordinator Area. This authority is consistent with the NERC Functional Model, the NERC Rules
of Procedure, and existing standards including IRO-001. Furthermore, the SDT believes that an effective Operating Plan cannot
be created without the RC assuring coordination among all of the applicable entities in its RC area as well as coordination with
its neighboring RC(s). The SDT has provided additional explanatory information in the draft to clarify what is intended by
coordination. Coordination has occurred when the applicable entities, in conjunction with the RC, have reviewed and accepted
the content of both the RC Operating Plan and the applicable entities’ respective Operating Procedures. To improve clarity Part
Consideration of Comments: Project 2013-03 | August 30, 2013
38
1.2 of Requirement R1 was changed from "A process for the RC to determine that the GMD Operating Procedures are
coordinated and compatible" to "A process for the Reliability Coordinator to review the GMD Operating Procedures". The SDT
believes the requirement to ensure coordination between and among RCs is addressed in existing IRO standards. (Refer to IRO014, Requirement R1). Therefore, the SDT has not added a duplicate requirement for coordination between and among RCs.
Comments on the need for vulnerability assessments. Commenters stated studies were needed to develop procedures. The
SDT believes the stage 1 standard meets the directives contained in FERC Order No. 779. The SDT recognizes that EOP-010 may
be implemented without vulnerability assessments and specific action triggers based on system studies. The SDT believes that
prudent steps to manage impacts of GMD on the power system can be undertaken, even in the absence of vulnerability
assessments and equipment-specific action triggers. The SDT agrees that system studies will result in improved Operating
Procedures, which may be part of an entity’s mitigation strategy in stage 2 of the GMD reliability standards.
Organization
Yes or No
Manitoba Hydro
No
Question 2 Comment
(1) R 1.1: This requirement needs clarification. It refers to a GMD Operating Plan requiring “a
description of activities designed to mitigate the effects of GMD events....”. It is not clear
whether the “activities” are intended to be performed by the Reliability Coordinator or refer to
the Operating Procedures of the Transmission Operators / Balancing Authorities, or some other
type of activity directed by the Reliability Coordinator, but performed by other entities. FERC
Order 779 only referred to a possible “coordination “ of Operating Procedures and that element
is captured separately in R 1.2. (2) R 1.2: The requirement for “compatibility” of Operating
Procedures causes concern and should be deleted. FERC Order 779 ( Par. 38) specified that GMD
standards “should allow responsible entities to tailor their operational procedures based on the
responsible entity’s assessment of entity-specific factors, such as geography, geology and system
topology. While FERC also directed NERC to consider the “coordination” of such operational
procedures, it did not require the “compatibility” of such procedures. Manitoba Hydro already
has in place operating procedures to respond to GMD events. The role of Manitoba Hydro’s
Reliability Coordinator is to notify Manitoba Hydro of GMD events and disseminate information
on present and forecasted storm levels. This would be appropriately viewed as coordination.
However, requiring a Reliability Coordinator to determine the “compatibility” of several entities’
Operating Procedures goes beyond coordination and begs the question of what happens if
there is a determination that certain Operating Procedures are not compatible. Does the
Consideration of Comments: Project 2013-03 | August 30, 2013
39
Organization
Yes or No
Question 2 Comment
Reliability Coordinator have the authority to direct an entity to adopt a different procedure? If
so, it is not clear how it would be determined which responsible entity must change its
procedures. Most importantly, this requirement erodes the discretion that was granted to
Transmission Operators and Balancing Authorities under Order 779.
ACES Standards
Collaborators
No
(1) Having another duplicative “operating plan” does not improve reliability on the bulk electric
system. The reliability standards already require several types of plans that could be enhanced
to address GMD events. While we agree that flexibility is better than specificity, we disagree
with the approach that another plan is required. The drafting team should consider enhancing
existing operating plans and other approaches to respond to the FERC directive.(2) We believe
that NERC should respond to the FERC directive with an equally efficient and effective alternative
to developing a new reliability standard. Since the new standard will be largely redundant with
with existing standards requirements, there is technical justification to support an alternate
approach. The alternate approach would include relying on existing standards requirements. For
example, IRO-014-1 R1 requires the RC to have operating procedures, processes or plans for
activities that require notification or exchange of information with other reliability coordinators.
Since the electric industry already takes an “all hazards” approach to planning the operation of
the grid, the RCs in geographies with greater risks to GMD events should be able to rely on
existing processes, procedures and plans to coordinate responses to GMD events. The electric
industry’s excellent response to large events such as hurricanes has proven the “all hazards”
approach to planning is effective.(3) A reliability standard is not always the best solution to
address a reliability concern. This standard is similar to cold weather preparedness, where there
are geographic differences and increased risks to reliability in particular locations. We cannot
support a standard that attempts to address the issue in broad generalities. GMD events should
be discussed at a regional level, technical guidance documents should be issued for utilities in
high risk locations, and practical solutions should be reached at each region.
JEA
No
A vulnerability study is required before good operating procedures can be developed
American Public
Power
No
APPA suggests that the word “all” in Requirement R1.2, be replaced with the word “applicable.”
APPA believes using the word “all” in this context will bring into applicability TOs and BAs that
Consideration of Comments: Project 2013-03 | August 30, 2013
40
Organization
Yes or No
Association
Question 2 Comment
have transformers below the 200 kV threshold. Replacing “all” with “applicable” will limit
confusion and avoid conflict with the applicability section of the standard.APPA is also concerned
with the words “coordinated and compatible” in R1.2. On the July 30th webinar the SDT stated
that a full scale power flow analysis would be the ideal way for the RC to determine compatibility
of various plans. APPA is concerned with the cost to TOs and BAs of meeting this “ideal”
therefore we suggest that the SDT give guidance on acceptable alternatives.
Florida Municipal
Power Agency
No
Bullet 1.2 puts RC’s in a position of responsibility without authority, or at least implies such. The
bullet requires the RC to “determine” that the plans of the BAs and TOPs are coordinated. What
happens if, through that process, the plans are determined not to be coordinated? Is the RC
compliant? What would the RC do to get the plans to be coordinated? Does the RC have the
authority necessary to cause this coordination? FMPA suggests looking at the EOP-006 and EOP005 construct for guidance.And as stated in response to question 1, the BA should not be an
applicable entity.
Minnkota Power
Cooperative, INC.
No
Comment #1) Suggest changing language in M1 for clarity and also to replace "implemented"
with “coordinated”. M1 should read:M1. Each Reliability Coordinator shall have a GMD
Operating Plan meeting all the provisions of Requirement R1; and evidence such as a revision
history to indicate that the GMD Operating Plan has been maintained; and evidence to show that
development and maintenance of the plan was coordinated with Transmission Operators and
Balancing Authorities. Rationale: The use of the word implemented implies that the actionable
items within the Operating Plan were executed as designed to mitigate the effects of a GMD
event. This is an “event driven” measure but the Requirement is to “coordinate” GMD Operating
Plans. By using “coordinate” (vice implement) within the Measure, the measure uses the same
words as the Requirement.Comment #2) Suggest replacing the word “all” in R1.2 to
“applicable”.Rationale: Using the word “all” could be interpreted such that TO’s and BA’s that
have transformers below 200kV could be affected. Replacing “all” with “applicable” would avoid
confusion, and be in alignment with the SDT intent.
Los Angeles
Department of
No
Even at this early stage of standard development it is generally agreed that system wide
approaches are required to prevent equipment damage and the possibility of uncontrolled
Consideration of Comments: Project 2013-03 | August 30, 2013
41
Organization
Yes or No
Water and Power
Question 2 Comment
separation, or cascading outages, and that partial measures are likely to relocate and or
concentrate the effects of GIC’s, therefore R1 lacks a crucial element to insure grid reliability. At a
minimum, the GMD operating plan should also include: R1.1.3 A process for the Reliability
Coordinator to determine the need for and invoke the GMD operating procedures for a specified
level response by a specified time, and a means of verifying all parties within the Reliability
Coordinator Area are in compliance before that specified time. Also a process to determine and
invoke an end to GMD events.Note: see R1 comment, R1.1.2 should include Generator Operators
in addition to Transmission Operators and Balancing Authorities.
Los Angeles
Department of
Water and Power
No
Even at this early stage of standard development it is generally agreed that system wide
approaches are required to prevent equipment damage and the possibility of uncontrolled
separation, or cascading outages, and that partial measures are likely to relocate and or
concentrate the effects of GIC’s, therefore R1 lacks a crucial element to insure grid reliability. At a
minimum, the GMD operating plan should also include: R1.1.3 A process for the Reliability
Coordinator to determine the need for and invoke the GMD operating procedures for a specified
level response by a specified time, and a means of verifying all parties within the Reliability
Coordinator Area are in compliance before that specified time. Also a process to determine and
invoke an end to GMD events.Note: see R1 comment, R1.1.2 should include Generator Operators
in addition to Transmission Operators and Balancing Authorities.
Great River
Energy
No
GRE agrees with the MRO NSRF on the suggested language change in M1 for clarity and also to
replace "implemented" with “coordinated”. M1 should read:M1. Each Reliability Coordinator
shall have a GMD Operating Plan meeting all the provisions of Requirement R1; and evidence
such as a revision history to indicate that the GMD Operating Plan has been maintained; and
evidence to show that development and maintenance of the plan was coordinated with
Transmission Operators and Balancing Authorities. Rationale: The use of the word implemented
implies that the actionable items within the Operating Plan were executed as designed to
mitigate the effects of a GMD event. This is an “event driven” measure but the Requirement is to
“coordinate” GMD Operating Plans. By using “coordinate” (versus implement) within the
Measure, the measure uses the same words as the Requirement.This standard is similar to cold
weather preparedness, where there are geographic differences and increased risks to reliability
Consideration of Comments: Project 2013-03 | August 30, 2013
42
Organization
Yes or No
Question 2 Comment
in particular locations. GMD events should be discussed at a regional level, technical guidance
documents should be issued for utilities in high risk locations, and practical solutions should be
reached at each region.
Northern
California Power
Agency
No
I think there is too much latitude given. The guidance document describes GMD as more a global
issue; not just a regional issue. I believe the guidance document provides a good list of activities
for an RC to start with, but that these activities should be consistent between various RCs as well
as the process the RCs will use to determimne if the TOP and BAs are coordinated and
compatible.
DTE Electric
No
Instead of each RC, TO and BA developing its own plan to mitigate effects of GMDs, the standard
should state that each TO and BA have a plan to support its RC's GMD plan. If individually
created, the plans may conflict.
PacifiCorp
No
PacifiCorp supports Florida Municipal Power Agency’s position as it relates to Question 2. R1.2
requires the RC to "determine" that the plans of the BAs and TOPs are coordinated but it is not
clear what happens if, through that process, the plans are determined not to be coordinated? Is
the RC compliant? What would the RC do to get the plans to be coordinated? Does the RC have
the authority necessary to cause this coordination? PacifiCorp supports FMPA’s suggestion to
look at the EOP-006 and EOP-005 construct for guidance.
American Electric
Power
No
R1, 1.2We are concerned by requiring the RC to “coordinate” Operating Procedures, and
determine their collective compatibility. Exactly what actions would demonstrate coordination,
and how could compliance of it be proven or shown? The word “coordinate” is very subject to
interpretation, and could be inconsistently applied in various audits.R1.2 states that the GMD
Operating Plan shall include “A process for the RC to determine that the GMD Operating
Procedures ... are coordinated and compatible.” This could potentially result in different
coordination requirements in different regions and consequently, prevent entities who are
operating in multiple regions to use consistent procedures within an entity’s service territory.
City of
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission
Consideration of Comments: Project 2013-03 | August 30, 2013
43
Organization
Yes or No
Tallahassee Electric Utility
Question 2 Comment
Operators and Balancing Authorities are coordinated and compatible. TAL recommends
replacing “all TOPs and BAs” with “applicable TOPs and BAs”. Additionally, the RC has to prove
all the plans are “coordinated and compatible”. This was a large undertaking for the EOP-006
restoration plans, and will be equally burdensome to the RC for these plans.
City of
Tallahassee
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission
Operators and Balancing Authorities are coordinated and compatible. TAL recommends replacing
“all TOs and BAs” with “applicable TOs and BAs”. Additionally, the RC has to prove all the plans
are “coordinated and compatible”. This was a large undertaking for the EOP-006 restoration
plans, and will be equally burdensome to the RC for these plans.
City of
Tallahassee
No
R1.2 requires the RC to determine that the GMD Operating Procedures of all Transmission
Operators and Balancing Authorities are coordinated and compatible. TAL recommends replacing
“all TOs and BAs” with “applicable TOs and BAs”. Additionally, the RC has to prove all the plans
are “coordinated and compatible”. This was a large undertaking for the EOP-006 restoration
plans, and will be equally burdensome to the RC for these plans.
Farmington
Electric Utility
System
No
Recommend rewording R1.2 “A process for the Reliability Coordinator to coordinate GMD
Operating Procedures and mitigating steps or tasks with Transmission Operators and Balancing
Authorities in the Reliability Coordinator Area.” FEUS has concerns with how the RC would
ensure ALL the TOP and BA plans are coordinated and compatible. In addition, FEUS is unclear
what demonstrates a plan is compatible.
NV Energy
No
Requiring the RC to develop and maintain a plan is an appropriate requirement; however, it is
unclear what the RC must do under 1.2 to "determine" that the GMD Operating Procedures in its
area are coordinated and compatible. Suggest a language change to "A process for the RC to
review and coordinate the GMD Operating Procedures of all TOP's in the RC Area."
MRO NERC
Standards Review
Forum (NSRF)
No
Suggest changing language in M1 for clarity and also to replace "implemented" with
“coordinated”. M1 should read:M1. Each Reliability Coordinator shall have a GMD Operating Plan
meeting all the provisions of Requirement R1; and evidence such as a revision history to indicate
Consideration of Comments: Project 2013-03 | August 30, 2013
44
Organization
Yes or No
Question 2 Comment
that the GMD Operating Plan has been maintained; and evidence to show that development and
maintenance of the plan was coordinated with Transmission Operators and Balancing
Authorities. Rationale: The use of the word implemented implies that the actionable items within
the Operating Plan were executed as designed to mitigate the effects of a GMD event. This is an
“event driven” measure but the Requirement is to “coordinate” GMD Operating Plans. By using
“coordinate” (vice implement) within the Measure, the measure uses the same words as the
Requirement.
Bureau of
Reclamation
No
The Bureau of Reclamation (Reclamation) and Western Area Power Administration (WAPA)
recommend that R1 should also require Reliability Coordinators (RCs) to be responsible for
monitoring space weather information and alerting TOPs and BAs. Currently IRO-005-3.1a R3
requires RCs to ensure that TOPs and BAs are aware of GMD forecast information. . This
responsibility should be enhanced in EOP-010-1 R1 and should require RCs to monitor space
weather information and alert TOPs and BAs when GMD watches and warnings begin and end,
and to determine what GMD responses are necessary within the RC footprint. For example, the
drafting team could add sub-requirement 1.3 to require, “A process for the Reliability
Coordinator to monitor space weather information and issue alerts to Transmission Operators
and Balancing Authorities when GMD watches and warnings are initiated, and what GMD
mitigation actions may be required in response to the GMD event.”
Oncor Electric
Delivery
Complany LLC
No
The proposed language of R1 assumes all Regions operate the same therefore in order to support
the structure of Regions across the North American utility industry, Oncor recommends R1 be
revisedto:”Each Reliability Coordinator shall coordinate the development and maintain a GMD
Operating Plan with its Balancing Authority, Transmission Owners, Transmission Operators,
Generator Owners, and Generator Operators that coordinate GMD Operating Procedures within
its Reliability Coordinator Area. At a minimum, the GMD Operating Plan shall include:” Oncor
believes the RC should remain responsible for implementing the plan.
NIPSCO
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC
reaching levels that would harm transformers. There is also historical evidence of the presence
of and correspondingly the absence of GIC in systems. These two factors should be used to
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45
Organization
Yes or No
Question 2 Comment
determine if a TOP/BA needs to develop, maintain, and implement Operating Procedures to
mitigate the effects of GMD events on the reliable operation of its respective system. If the
conditions for GIC do not exist and there is no history of GIC induced damage or misoperation, a
RC should not be required to include those TOP/BAs in coordinating plans for GMD other than to
provide assistance as required in other standards.
Puget Sound
Energy
No
This requirement imposes a heavy burden on the RC. Understanding that some level of
coordination is required, perhaps a lesser level of coordination will be acceptable, at least until
phase 2 of the project is complete. Such coordination could be modeled after the approach in
IRO-010, where the RC would set the specifications for the TOP Operating Plans and the TOP
would be required to comply with those specifications.
Texas Reliability
Entity
No
This wording in R1 and R3 are “fill-in-the-blank” type of requirements that NERC has been trying
to move away from. We understand that Phase 2 of the GMD Standard project will provide
additional details and clarification.
Tri-State
Generation and
Transmission
Association, Inc.
No
Tri-State believes that the proposed standard, as written, is too vague and gives the Reliability
Coordinator too much latitude to create plans as only it deems appropriate. It also does not
provide for industry review of these plans beforehand. Requirement R1 appears to be a "fill in
the blank" requirement, which FERC does not approve.
Emprimus LLC
and Volkmann
Consulting
No
We agree with the language of develop, maintain and implement a GMD Operating Plan.
However, the requirement does not have any evaluation of whether the Operating Plan was
appropriately and effectively implemented for an event. M1 should include a post-event
evaluation activity and subsequent documentation of the plan implementation.
Salt River Project
No
We believe that the requirement should state that the Reliability Coordinator should establish
triggers that are appropriate for the given geographical and system exposure for each TO or BA.
We would suggest language such as the following:R1.1 The Reliability Coordinator shall create a
preliminary assessment of the exposure for each BA and TO. The plan and procedures developed
by the Reliability Coordinator shall establish trigger levels for initiating and terminating these
Consideration of Comments: Project 2013-03 | August 30, 2013
46
Organization
Yes or No
Question 2 Comment
plans or procedures based on the preliminary assessment of exposure for each BA or TO.
Duke Energy
Yes
Duke Energy believes R1.2 should be changed to “Each Reliability Coordinator shall have an
Operating Process to determine that the GMD Operating Procedures of all Transmission
Operators and Balancing Authorities in the Reliability Coordinator Area are coordinated and
compatible.”
Public Utility
District No.1 of
Snohomish
County
Yes
Appropriate implementation time should be given so that the RC has time to develop the GMD
operating plan and coordinate with neighboring RCs as well as other impacted functions.
Although GMD and Geomagnetically Induced Currents (“GIC”) have been well understood for
many decades, how they impact various elements of the power grid are still being assessed by
the electric industry and equipment manufactures. Recent work presented at the 2013 IEEE PES
General meeting by Emanuel Bernabeu, Dominion “Overview of GMD Phenomena and ways to
study the impact on the transmission system” and Ramsis Girgis, ABB “Equipment issues
transformers, (Major Concern)'s etc. -from the transformers committee, impacts on transformer
fleet and new designs” will provide more insight into appropriate actions to be taken by the RC
and impacted functions. Significant discussion has taken place on this subject in many different
forums; however there is very little credible analysis on how GMD can impact the BES and what
level of risk does GMD pose compared to other adverse impact events. See IEEE Power & Energy
article “Geomagnetic Disturbances” by IEEE Power and Energy Society Technical Council Task
Force on Geomagnetic Disturbances, July/August 2013 pg. 71-78.
Bonneville Power
Administration
Yes
BPA’s position is that the primary entities responding to GMD events are the TOPs and BAs. BPA
believes the RC should be required to develop the criterion for their Operating Plan in direct
coordination with the TOPs and BAs in their area in order to avoid the RC developing a plan that
may not be compatible with the region. Additionally, the RC should be the primary source of
space/weather information and be required to disemminate that information to the TOPs and
BAs in their area.
CenterPoint
Energy
Yes
CenterPoint Energy agrees in general with proposed Requirement 1 but offers an alternative
proposal on specific aspects of the Requirement. We propose that the SDT modify R1 to read as
Consideration of Comments: Project 2013-03 | August 30, 2013
47
Organization
Yes or No
Question 2 Comment
follows: Each Reliability Coordinator shall develop, maintain, and implement a GMD Operating
Plan consisting of Operating Procedures developed by the Reliability Coordinator and
coordination of GMD Operating Procedures that may be developed by individual Transmission
Operators and Balancing Authorities within its Reliability Coordinator Area.Discussion: We
believe it is not necessary, beneficial, or efficient for each and every applicable Transmission
Operator and Balancing Authority to try to develop GMD-related Operating Procedures and for
the Reliability Coordinator to then try to harmonize multiple individual Operating Procedures in a
way that benefits the region as a whole. We believe the most efficient and beneficial approach is
for the Reliability Coordinator to develop an Operating Plan for the region, but allow (not
require) individual Transmission Operators and Balancing Authorities to supplement the
Reliability Coordinator’s Operating Plan with individual Transmission Operator or Balancing
Authority Operating Procedures, as along as those individual Operating Procedures, if any, are
coordinated by the Reliability Coordinator.As repeatedly and correctly noted in the FERC Order,
GMD assessment and mitigation requires a wide-area view. We believe some, if not most,
individual Transmission Operators and Balancing Authorities will not be in a good position to
reasonably determine what GMD-related operating actions would benefit the reliable operation
of the entire region. Indeed, for some individual Transmission Operators and Balancing
Authorities, it is possible and we believe likely that no action by that individual party is necessary
or beneficial for the reliability of the region as a whole. The Reliability Coordinator has the widearea view and is in the best position to determine what Operating Procedures would benefit the
region as a whole. However, we also recognize that some individual Transmission Operators or
Balancing Authorities may have already developed and implemented Operating Procedures, or
may do so in the future based on specific concerns or vulnerabilities identified at some future
time. We believe that it is beneficial to allow (but not require) individual Transmission Operators
and Balancing Authorities to develop individual Operating Procedures based upon that entity’s
detailed knowledge and assessment of its facilities, as long as provision is made for the Reliability
Coordinator to coordinate such discretionary individual procedures that would supplement the
regional procedures.If the SDT agrees with CenterPoint Energy’s proposal, the language of R1.2
would probably need to be modified by changing “...GMD Operating Procedures of all
Transmission Operators and Balancing Authorities...” to “...GMD Operating Procedures of any
submitted Transmission Operators and Balancing Authorities...”. Also, R3 would need to be
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48
Organization
Yes or No
Question 2 Comment
modified. R4 and R5 would be deleted. CenterPoint Energy will discuss proposed changes to R3
in response to the next question.
Northeast
Utilities
Yes
I agree that the RC should coordinate the plans for the BAs and TOPs in its area. It might be
beneficial that there be coordination at the RRO level so that RC plans are coordinated as well,
since GMDs/ GICs do not recognize arbitrary system borders.
Xcel Energy
Yes
In general, we agree with R1 & R1.1. However, we feel that R1.2 should be modified. Instead, we
recommend the requirement read something like this: [1.2 A process for the Reliability
Coordinator to coordinate GMD Operating Procedures and mitigating steps or tasks with
Transmission Operators and Balancing Authorities in the Reliability Coordinator Area.]
SERC OC Review
Group
Yes
Language should be added to ensure coordination between adjacent RCs.
Entergy Services,
Inc.
Yes
Language should be added to ensure coordination between adjacent RCs.
PJM
Interconnection,
L.L.C.
Yes
PJM has also signed onto SERC's comments.
Western
Electricity
Coordinating
Council
Yes
Requirement is acceptable, but implementaiton period is too short
Southern
Company
Yes
The SDT should consider creating criteria for the RC to use to ensure plans are coordinated and
compatible. For example, criteria were developed for RCs to use to approve TOP restoration
plans in EOP-006-2, R5, which indicates that the “Reliability Coordinator shall determine whether
the Transmission Operator’s restoration plan is coordinated and compatible with the Reliability
Coordinator’s restoration plan and other Transmission Operators’ restoration plans within its
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49
Organization
Yes or No
Question 2 Comment
Reliability Coordinator Area.” Similarly, the SDT or a committee designated by the SDT should
create criteria for RCs to use to ensure plans are coordinated and compatible.
Western Area
Power
Administration
Yes
Western Area Power Administration (WAPA) and the Bureau of Reclamation (Reclamation)
believe that R1 should also require Reliability Coordinators (RCs) to be responsible for monitoring
space weather information and alerting TOPs and BAs. Currently IRO-005-3.1a R3 requires RCs to
ensure that TOPs and BAs are aware of GMD forecast information. . This responsibility should be
enhanced in EOP-010-1 R1 and should require RCs to monitor space weather information and
alert TOPs and BAs when GMD watches and warnings begin and end, and to determine what
GMD responses are necessary within the RC footprint. For example, the drafting team could add
sub-requirement 1.3 to require, “A process for the Reliability Coordinator to monitor space
weather information and issue alerts to Transmission Operators and Balancing Authorities when
GMD watches and warnings are initiated, and what GMD mitigation actions may be required in
response to the GMD event.”
SPP Standards
Review Group
Yes
While we concur that R1 addresses the FERC directive, we have some reservations with the use
of the word ‘coordinated’ in R1.2 especially along the lines of what specifically will be required by
the responsible entities to show coordination. Hopefully, the Reliability Coordinator will provide
those details in his processes. Additionally, we would encourage the NERC Operating Reliability
Subcommittee to ensure consistency in the processes used by the Reliability Coordinators
throughout NERC.
Pepco Holdings
Inc & Affiliates
Yes
Hydro One
Networks Inc.
Yes
Dominion
Yes
seattle city light
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
50
Organization
Yes or No
Northeast Power
Coordinating
Council
Yes
Oklahoma Gas &
Electric
Yes
FirstEnergy
Yes
Arizona Public
Service Company
Yes
Colorado Springs
Utilities
Yes
Question 2 Comment
Foundation for
Yes
Resilient Societies
Exelon and its
Affiliates
Yes
American
Transmission
Company
Yes
Independent
Electricity System
Operator
Yes
ReliabilityFirst
Yes
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51
Organization
Yes or No
LCRA
Transmission
Services Corp
Yes
Public Utility
District No. 2 of
Grant County,
WA
Yes
Ben Li Associates
Yes
City of Austin dba
Austin Energy
Yes
Idaho Power
Company
Yes
Electric Reliability
Council of Texas,
Inc.
Yes
Luminant
Generation
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
Question 2 Comment
52
3. In Requirement R3, the SDT is proposing to require each applicable Transmission Operator and Balancing Authority to develop,
maintain, and implement GMD Operating Procedures. The draft Standard is intended to allow each entity to develop its own
procedures based on entity-specific factors as directed in Order No. 779. Do you agree that the SDT has correctly addressed the
stage 1 directives in Order No. 779? If you do not agree that this requirement addresses the directive, or you agree in general but
feel that alternative language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on Requirement R3. All comments have been reviewed and the
revised version of EOP-010-1 includes changes that the drafting team considers appropriate. Several changes such as the removal of BA
applicability have been explained in preceding sections. The drafting team agrees that an “Operating Process” as defined in the NERC
Glossary of Terms can satisfy the reliability objective of R3 and has modified the requirement so that it can be satisfied by either an
Operating Procedure or an Operating Process. The drafting team modified part 3.1 which addresses space weather information in the
Transmission Operator's GMD Operating Procedure or Operating Process. A summary of comments and the drafting team's response is
provided below:
Avoid overlapping requirements for space weather information. Some commenters indicated that Requirement 3, Part 3.1 is
unnecessary or could conflict with IRO-005-3.1a Requirement R3. The drafting team believes that receiving space weather
information is an essential component to GMD Operating Procedures or Processes. The drafting team changed the language in
Part 3.1 from "steps or tasks for the acquisition and dissemination of space weather information" to "steps or tasks to receive
space weather information". The change reinforces the RC's responsibility to provide information that is relevant to reliability,
while recognizing that Transmission Operators may use several sources in addition to the RC's disseminated forecast information
to obtain more detailed local or system-specific information.
A commenter suggested guidelines be developed by a technical committee. The GMD Task Force, which reports to the Planning
Committee, has developed technical resources including the 2012 GMD Report and the Operating Procedure templates, which
are posted on the GMD Task Force page of the NERC website. Additional technical resources and operator training are included
in the GMD Task Force project plan. EOP-010-1 is being developed in response to FERC directives.
Tailoring of operating procedures. A commenter requested that language be included in Requirement R3 to reflect that
entities are allowed to consider various entity-specific factors in developing GMD Operating Processes or Procedures. The
drafting team agrees with the principle that an entity can consider entity-specific factors in developing its process and
procedure. However the suggested language is not a measureable requirement for mandatory compliance and therefore this
language has not been incorporated.
Consideration of Comments: Project 2013-03 | August 30, 2013
53
Organization
Yes or No
Question 3 Comment
ACES Standards
Collaborators
No
(1) The proposed standard is responsive to the FERC directive, but it fails to take into account
existing reliability standards that overlap with the proposed draft, and creates duplicative
requirements that could result in double jeopardy. For instance, TOP-004-2 R6.1 requires the
TOP to have policies and procedures for monitoring and controlling voltage levels and reactive
power flows. Since the electric industry has always taken an “all hazards” approach to planning
and operating the electric grid, these policies and procedures will have already considered
extreme operating situations such as events that might occur during a GMD event. These
policies and procedures would, therefore, be sufficient to respond to a GMD event without the
need to make them specific to the GMD event or without the need to create a duplicative
standard. The drafting team or a NERC technical committee, such as the Operating Committee,
could draft a reliability guideline to provide additional detail of how to prepare for GMD events
and make recommendations for utilities in areas susceptible to GMD events to include
preparations in their planning processes.
National Rural
Electric
Cooperative
Association
(NRECA)
No
As explained in response to Question 1, NRECA does not believe it is necessary to include the
Balancing Authority as an applicable entity in this standard.
Entergy Services,
Inc.
No
As mentioned in Q1, a BA with no 200 kV transformers may be intertwined with a TOP that does
have the issue and likely will be exposed to issues that the TOP faces and may need to develop,
maintain, and implement GMD Operating Procedures. The SDT should consider changing the high
side terminal voltage to greater than 300 kV.
Florida Municipal
Power Agency
No
As stated previously, the BA should not be an applicable entity. If transmission switching is
required that impacts contraints which in turn impacts dispatch, then existing procedures such as
TLR and procedures regarding ancillary services should be used. If the RC or TOP needs additional
generation to be commited or redispatch to occur, the RC or TOP already has the authority
Consideration of Comments: Project 2013-03 | August 30, 2013
54
Organization
Yes or No
Question 3 Comment
within the standards to require that additional unit commitment or redispatch.
City of Austin dba
Austin Energy
No
Austin Energy (AE) believes that staggered enforcement dates between R1 and R3 are necessary
for TOPs and BAs to develop Operating Procedures “that are coordinated with [their] Reliability
Coordinator’s GMD Operating Plan.” The current implementation plan establishes a single date
for all requirements. During the webinar, AE suggested this and the response was that NERC
anticipates that TOPs' Operating Procedures will be developed first so the timing is acceptable.
Given the definitions of Operating Plan and Operating Procedures in the NERC Glossary, AE
understands how an Operating Plan can be built based on a series of underlying Operating
Procedures, but if that is the intended order of operation, R3 should not require that Operating
Procedures be coordinated with the RC’s Operating Plan.
JEA
No
BA should be removed
Public Utility
District No.1 of
Snohomish
County
No
Because GMD can be a wide area event the BA and TOP efforts should focus on coordinating
operations and procedures with the RC. Also GMD is a High-Impact, Low-Frequency event so
overall risk to the TOP or BA area should be assessed to make certain the operations and
procedures are commensurate with the risk to reliable operation of the Bulk Electric System.
DTE Electric
No
Entities with no previous effects from GMDs should be exempted by their RX from developing a
plan and entities with potential problems with GMDs should be required to develop plans to
support their RC's plan and provide plan details to their RC.
Northern
California Power
Agency
No
In a perfect world this should already exist is folks are truely in compliance with IRO-005-3.1a R3.
How are the RCs, TOPs and Bas curently complying with IRO-005-3a? This might provide some
insight for the SDT.
NV Energy
No
OK, except "Balancing Authority" should be removed from R3.
PacifiCorp
No
PacifiCorp supports Florida Municipal Power Agency’s position as it relates to Question 3. As
stated previously, the BA should not be an applicable entity. If transmission switching is required
that impacts contraints which in turn impacts dispatch, then existing procedures such as TLR and
Consideration of Comments: Project 2013-03 | August 30, 2013
55
Organization
Yes or No
Question 3 Comment
procedures regarding ancillary services should be used. If the RC or TOP needs additional
generation to be commited or redispatch to occur, the RC or TOP already has the authority to
require that additional unit commitment or redispatch.
Salt River Project
No
Please see Comment for question 2. The requirements for the Reliability Coordinator should be
the same for the Transmission Operator and Balancing Authority.
Foundation for
No
Resilient Societies
Reason: Earlier comments on the Operating Procedure Templates submitted by the Foundation
for Resilient Societies were ignored, and not addressed on their merits by the GMD Task Force
management and by the NERC Planning Committee. See our previous comments at:
https://resilientsocieties.org/images/Comments Operating Procedure Template NERC GMDTF
Phase 2 Rev1.pdf.
Farmington
Electric Utility
System
No
Recommend revising 3.2. to the following, “The steps or tasks to be employed by System
Operators that are coordinated with its Reliability Coordinator to mitigate the effects on the
system from GMD events.” FEUS agrees it is pertinent mitigating activities are coordinated;
however, we believe this level or coordination should be in line with what is expected for
coordination activities during a restoration.
Xcel Energy
No
Recommend revising R3.1. It isn’t clear as to what periodicity that an entity should be collecting
and disseminating this information. Also, it is unclear as to what would qualify as a source to
meet this requirement (i.e. is any ‘space weather’ source acceptable?). Suggest removing this
requirement and indicate in prior requirement (R1) that RCs have the responsibility of collecting
and sharing space weather information with TOPs and BAs, and RCs must subscribe to an
authoritative space weather source.
Arizona Public
Service Company
No
Requirment 3.2 requires coordination with Reliability coordinator’s plan. Thus, there should be a
provision that this requirement is effective only 6 months after the Reliability coordinator’s plan
is available.
CenterPoint
No
See CenterPoint Energy’s response to the previous question. In this question, the SDT states,
Consideration of Comments: Project 2013-03 | August 30, 2013
56
Organization
Yes or No
Energy
Question 3 Comment
“The draft Standard is intended to allow each entity to develop its own procedures...”. There is a
difference between allowing each entity to develop its own procedures and requiring each entity
to do so. R3, as proposed, would do the latter. CenterPoint Energy’s proposed changes to R1
would allow, but not require, an individual entity to develop its own procedures that would
supplement required regional procedures developed by the Reliability Coordinator. If the SDT
agrees with CenterPoint Energy’s proposed change to R1, R3 would be modified to require
Transmission Operators and Balancing Authorities to submit individual Operating Procedures, if
any are developed, to the Reliability Coordinator so that the Reliability Coordinator could ensure
coordination that would benefit the region as a whole.CenterPoint Energy also has specific
concerns that R3.1 is unnecessary and unduly prescriptive. On page 24 of the FERC Order, FERC
describes NERC’s concern with reliance upon the most familiar means of characterizing space
weather information, the “K-Index”. On Page 30 of the Order, FERC acknowledged NERC’s
concern and took no position regarding overreliance on the K-Index to trigger operational
procedures. R3.3 appropriately allows the responsible entity to choose and then document for
compliance what the trigger mechanism would be, which could be space weather information or
some other mechanism (GIC monitoring, for example). If an individual entity concurs with
NERC’s view that space weather information is an unreliable means of triggering Operating
Procedures, then that entity should not be required to acquire and disseminate such
information.Proposed language changes to implement CenterPoint Energy’s suggestions are as
follows:R3 Each Transmission Operator and Balancing Authority that chooses to develop,
maintain, and implement Operating Procedures to supplement the Reliability Coordinator’s
Operating Plan described in R1 shall submit such supplemental Operating Procedures to the
Reliability Coordinator for review and approval. 3.1 DELETED 3.2 DELETED (addressed by R1.1)
3.3 Moved to Requirement 1 as R1.3R4 DELETED (addressed by R2)R5 DELETED
Texas Reliability
Entity
No
See comments for #2 above.
Seminole Electric
No
Seminole asks the SDT to add language to the Standard that indicates that Industry and NERC
intend to allow for consideration of various entity specific characteristics in developing a GMD
Operating Plan. Seminole is aware that this is the intent of the SDT and therefore Seminole
Consideration of Comments: Project 2013-03 | August 30, 2013
57
Organization
Yes or No
Question 3 Comment
proposes the following language, or similar language, be added in each Requirement requiring an
Entity to develop a type of GMD Operating Plan and/or set of Operating Procedures:”An Entity
can take into consideration such entity-specific factors such as geography, geology, and system
topology in developing a GMD Operating Plan/set of Operating Procedures.”Seminole believes
that this is not clear in the Requirement and wishes that the NERC SDT specifically state the
ability for an entity to tailor their plans and/or procedures to their environment. In addition, the
suggested language is pulled from the SAR for this project.
NIPSCO
No
There are geological and physical (circuit length) that correlate directly to the probability of GIC
reaching levels that would harm transformers. There is also historical evidence of the presence
of and correspondingly the absence of GIC in systems. These two factors should be used to
determine if a TOP needs to develop, maintain, and implement Operating Procedures to mitigate
the effects of GMD events on the reliable operation of its respective system. If the conditions for
GIC do not exist and there is no history of GIC induced damage or misoperation, the TOP should
not be required to have plans specifically for GMD events.
Oklahoma Gas &
Electric
No
This standard should not be applicable to the Balancing Authorities. FERC Order No. 779 directed
the ERO to develop one or more Reliability Standards that require owners and operators of the
BPS to develop and implement operational procedures to mitigate the effects of GMDs. The
functions of the BA center around balancing load and generation and implementing and
accounting for interchange schedules. BAs (unless they are also TOPs) do not monitor BES
elements such as transformers.
Western Area
Power
Administration
No
WAPA and Reclamation suggest that the drafting team remove sub-requirement R3.1. WAPA and
Reclamation believe it is inappropriate to place responsibility for acquiring space weather
information with the Transmission Operators (TOPs) and Balancing Authorities (BAs) because BES
reliability will not be enhanced when hundreds of individual entities must determine when a
GMD event begins and ends. Neighboring TOPs and BAs would likely react at different times
depending on their perception of when a GMD event begins, which could be chaotic and
contribute to system instability. As discussed above in response to Question 1, WAPA and
Reclamation believe that responsibility for monitoring space weather, determining when a watch
Consideration of Comments: Project 2013-03 | August 30, 2013
58
Organization
Yes or No
Question 3 Comment
or warning is appropriate, and alerting TOPs and BAs should be placed at least at the RC level and
possibly with a national coordinating entity. WAPA and Reclamation believe that the drafting
team should remove the current R3.1, and should renumber R3.2 and R3.3 to R3.1 and R3.2.
WAPA and Reclamation also suggest that the drafting team add a new R3.3 to require TOP and
BA Operating Procedures to address “The steps or tasks for receiving and disseminating space
weather information to its System Operators.”
Bureau of
Reclamation
No
WAPA and Reclamation suggest that the drafting team remove sub-requirement R3.1. WAPA and
Reclamation suggest that it is inappropriate to place responsibility for acquiring space weather
information with the Transmission Operators (TOPs) and Balancing Authorities (BAs) because BES
reliability will not be enhanced when hundreds of individual entities must determine when a
GMD event begins and ends. Neighboring TOPs and BAs would likely react at different times
depending on their perception of when a GMD event begins, which could be chaotic and
contribute to system instability. As discussed above in response to Question 1, WAPA and
Reclamation believe that responsibility for monitoring space weather, determining when a watch
or warning is appropriate, and alerting TOPs and BAs should be placed at least at the RC level and
possibly with a national coordinating entity. WAPA and Reclamation believe that the drafting
team should remove the current R3.1, and should renumber R3.2 and R3.3 to R3.1 and R3.2
respectively. WAPA and Reclamation also suggest that the drafting team add a new R3.3 to
require TOP and BA Operating Procedures to address “The steps or tasks for receiving and
disseminating space weather information to its System Operators.”
Emprimus LLC
and Volkmann
Consulting
No
We agree with the language stated in R3. However, R3 should include the requirement of the
TOP to communicate that they have implemented their Operating Procedures. Likewise the
requirement does not have any evaluation of whether the Operating Procedures were
appropriately and effectively implemented for an event. M3 should include a post-event
evaluation activity and subsequent documentation of the plan implementation
Los Angeles
Department of
Water and Power
No
While it is agreed that BAs and TOPs and GOs should develop and maintain Operating Procedures
to mitigate the effects of GMD events, doing so will protect the equipment and interest of said
BA, TOP or GO, but WILL NOT insure grid reliability or the elimination of conditions which could
Consideration of Comments: Project 2013-03 | August 30, 2013
59
Organization
Yes or No
Question 3 Comment
lead to uncontrolled separation, or cascading outages. These plans must be reviewed by the RC’s
technical team for their effect on other members of the interconnection, and approved or
modified to meet grid reliability considerations. Such modifications must be acknowledged and
agreed to by the Stakeholders, and invoked when directed by the RC (R3.3.1 and R3.3.3 are
inappropriate and should be replaced by the suggested R1.1.2 above in question 2 comments).
Los Angeles
Department of
Water and Power
No
Sacramento
Municipal Utility
District
No
Ben Li Associates
Yes
While it is agreed that BAs and TOPs and GOs should develop and maintain Operating Procedures
to mitigate the effects of GMD events, doing so will protect the equipment and interest of said
BA, TOP or GO, but WILL NOT insure grid reliability or the elimination of conditions which could
lead to uncontrolled separation, or cascading outages. These plans must be reviewed by the RC’s
technical team for their effect on other members of the interconnection, and approved or
modified to meet grid reliability considerations. Such modifications must be acknowledged and
agreed to by the Stakeholders, and invoked when directed by the RC (R3.3.1 and R3.3.3 are
inappropriate and should be replaced by the suggested R1.1.2 above in question 2 comments).
1. We agree with the proposed requirement. However, there currently exists a similar
requirement in IRC-005-3.1a, R3, which says:R3. Each Reliability Coordinator shall ensure its
Transmission Operators and Balancing Authorities are aware of Geo-Magnetic Disturbance
(GMD) forecast information and assist as needed in the development of any required response
plans.With the introduction of the EOP-010 standard, specifically Requirement R3, the TOP and
BA will have operating procedure in place and be required to monitored GMD activities on an
ongoing basis. We question the need to keep R3 of IRO-005-3.1a. If the latter is deemed
redundant after the adoption of the EOP-010 standard, we suggest the SDT to propose retiring
R3 of IRO-005-3.1a. 2. It R3 is to be retained, then it does not mention “applicable” BAs and
TOPs, which it should. Further, a BA or TOP should be able to adopt a template procedure
developed by its Reliability Coordinator. This should be explained in an administrative appendix
to the standard.
Consideration of Comments: Project 2013-03 | August 30, 2013
60
Organization
Yes or No
Question 3 Comment
Idaho Power
Company
Yes
Agree in General. Propose adding Generator Operator to R3 and M3. The Reliability Coordinator
needs to coordinate their procedures with the Transmission Operator, Balancing Authority and
Generator Operator.
Southern
Company
Yes
An additional requirement should be added requiring BA/TOPs to send their initial plans and any
revisions to the RC for review, since the RC has responsibility for ensuring plans are coordinated
and compatible.
Great River
Energy
Yes
Because of the wide-area nature of a GMD event, GRE is suggesting a higher level authority such
as the NERC Operating Committee or a NERC technical committee consider drafting guidelines to
provide details in preparing for GMD events that would include recommendations to entites in
areas susceptible to GMD events.
PJM
Interconnection,
L.L.C.
Yes
PJM has signed onto SERC's comments. PJM also signs onto the SRC's response to Question #3.
Exelon and its
Affiliates
Yes
R3.3, font is incorrect - need the entire number to be bold.
Northeast
Utilities
Yes
The language in R3 is adequate.
Tri-State
Generation and
Transmission
Association, Inc.
Yes
Tri-State agrees that R3 properly addressed FERC Order No. 779, but believes the
implementation periods should be modified. A 6 month implementation period requiring the
Reliability Coordinator to develop the Operating Plan and the Transmission Operator/Balancing
Authority to develop the Operating Procedures is not suitable. The Transmission
Operator/Balancing Authority needs time to ensure their procedures are in accordance with the
Reliability Coordinator's Operating Plan so the implementation dates need to be staggered.
Independent
Yes
We agree with the proposed requirement. However, there currently exists a similar requirement
Consideration of Comments: Project 2013-03 | August 30, 2013
61
Organization
Yes or No
Electricity System
Operator
Question 3 Comment
in IRC-005-3.1a, R3, which says:R3. Each Reliability Coordinator shall ensure its Transmission
Operators and BalancingAuthorities are aware of Geo-Magnetic Disturbance (GMD) forecast
information and assist asneeded in the development of any required response plans.With the
introduction of the EOP-010 standard, specifically Requirement R3, the TOP and BA will have
operating procedure in place and be required to monitored GMD activities on an ongoing basis.
We question the need to keep R3 of IRO-005-3.1a. If the latter is deemed redundant after the
adoption of the EOP-010 standard, we suggest the SDT to propose retiring R3 of IRO-005-3.1a.
Electric Reliability
Council of Texas,
Inc.
Yes
MRO NERC
Standards Review
Forum (NSRF)
Yes
SERC OC Review
Group
Yes
Pepco Holdings
Inc & Affiliates
Yes
Hydro One
Networks Inc.
Yes
We agree with the proposed requirement. However, there currently exists a similar requirement
in IRC-005-3.1a, R3, which says:R3. Each Reliability Coordinator shall ensure its Transmission
Operators and BalancingAuthorities are aware of Geo-Magnetic Disturbance (GMD) forecast
information and assist asneeded in the development of any required response plans.With the
introduction of the EOP-010 standard, specifically Requirement R3, the TOP and BA will have
operating procedures in place and be required to monitor GMD activities on an ongoing basis.
We question the need to keep R3 of IRO-005-3.1a. If the latter is deemed redundant after the
adoption of the EOP-010 standard, we suggest the SDT propose retiring R3 of IRO-005-3.1a. If R3
is to be retained, then it does not mention “applicable” BAs and TOPs, which it should.
Consideration of Comments: Project 2013-03 | August 30, 2013
62
Organization
Yes or No
Dominion
Yes
seattle city light
Yes
Northeast Power
Coordinating
Council
Yes
FirstEnergy
Yes
SPP Standards
Review Group
Yes
Bonneville Power
Administration
Yes
Colorado Springs
Utilities
Yes
American Electric
Power
Yes
American
Transmission
Company
Yes
The United
Illuminating
Company
Yes
ReliabilityFirst
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
Question 3 Comment
63
Organization
Yes or No
LCRA
Transmission
Services Corp
Yes
Public Utility
District No. 2 of
Grant County,
WA
Yes
Oncor Electric
Delivery
Complany LLC
Yes
Minnkota Power
Cooperative, INC.
Yes
Duke Energy
Yes
American Public
Power
Association
Yes
Luminant
Generation
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
Question 3 Comment
64
4. In Requirements R2 and R4 the SDT is proposing to require applicable entities to review their GMD Plans/Operating Procedures
every 36-months. This periodicity would ensure improvements in the scientific understanding of GMDs can be incorporated into
Operating Procedures in a timely manner as directed in Order No. 779. In Requirement R5, the SDT is proposing to require each
applicable Transmission Operator and Balancing Authority to have a copy of its GMD Operating Procedures in its Primary and
Back-up Control Rooms, which is consistent with other EOP reliability standards. Do you agree that the SDT has correctly
addressed the directives in Order No. 779 in a manner that is good for reliability with these requirements? If you do not agree, or
you agree in general but feel that alternative language would be more appropriate, please provide specific suggestions in your
comments.
Summary Consideration: The drafting team thanks all who commented on Question 4. The drafting team reviewed all comments and
has incorporated changes into a revised version of EOP-010-1. The drafting team agrees that applicable entities will be required to
review and update its GMD Operating Plans, Procedures, and/or Processes in order to meet the requirement to maintain them in
Requirements R1 and R3. As a result, Requirements R2 and R4 from the initial draft of EOP-010-1 have been deleted in the revised
version as administrative and duplicative, consistent with the Paragraph 81 criteria (submitted to FERC in Docket No. RM13-8-000).
Additionally, Requirement R5 was determined to be unnecessary for reliability and deleted in the revision because Requirements R1 and
R3 require that applicable entities implement their GMD Operating Plans, Procedures, and Processes. The drafting team believes that
these revisions have produced a clear, high quality, technically sound and results-based standard.
Organization
Yes or No
ACES Standards
Collaborators
No
Question 4 Comment
(1) Requirements R2, R4 and R5 meet one or more Paragraph 81 criteria and should not be
written as separate requirements that will result in a separate violation for failing to conduct the
review on a timely basis or failing to have a copy of the operating plan or procedure in the
control centers. A requirement is subject to retirement under P81 if the requirement fits any of
the following criteria: it is administrative in nature, requires data collection/data retention,
purely documentation or reporting, requires periodic updates, concerns only a commercial or
business practice, is redundant with other standards, hinders the protection or reliable operation
of the BES, or has little, if any, value as a reliability requirement.(2) Requirement R5 is very
Consideration of Comments: Project 2013-03 | August 30, 2013
65
Organization
Yes or No
Question 4 Comment
similar to CIP-003-3 R4 which requires the cyber security policy to be available to all personnel
with access to or responsibility for Critical Cyber Assets. In the P81 NOPR, FERC recently
proposed to approve retiring CIP-003-3 R4 because it is administrative and it would be not be
practical to implement the cyber security policy if it was not available to personnel. Similarly, R5
would be redundant with R3 because R3 has an implementation requirement. How can the TOP
or BA implement the operating procedure if it is not available to its operating personnel per R5?
How would an auditor verifying that a copy of the plan in the primary and backup control rooms
benefit reliability? It could be placed in these rooms with no notification to system operators
and no training provided to system operators on the implementation. Obviously, this would not
support reliability. Requirements R2 and R4 are similar to the NUC-001-2 R9.13 which compel
the Nuclear Plant Generator Operator and Transmission Entity to review their agreement every
three years. FERC also proposed to retire it. Thus, R2 and R4 should be removed. If some
vestige R2 and R4 are to remain, they should be made a sub-part of R1 and R3 so that a separate
violation is not recorded for failure to review in the 36 month time frame. (3) We do agree that
the 36-month time frame for review is reasonable.
Dominion
No
As R2 and R4 are currently written, they are purely administrative and do nothing to improve or
insure reliability. R1 requires the GMD Operating Plan be maintained which infers the need to
review on a periodic basis.
Sacramento
Municipal Utility
District
No
Every 36 months is too short of a time-frame. It would be more appropriate to have a review of
a potential plan, if indeed needed, when system configurations warrant a review. The review
period should be set by the entity, IF there is even a concern.
Exelon and its
Affiliates
No
Exelon believes that performing a review of GMD Plans / Operating Procedures every 36 months
is contrary to the Paragraph 81 criteria whose effort was to remove truly administrative
requirements that do not have an impact on electric grid reliability. We feel tha R2, M2 and R2,
M4 should be removed.
NextEra Energy
No
NextEra Energy is pleased with the work the GMD SDT has done in a very quick period of time,
with the exception of adding certain requirements that no longer fit within the paradigm under
Consideration of Comments: Project 2013-03 | August 30, 2013
66
Organization
Yes or No
Question 4 Comment
which Standards are to be drafted. NextEra suspects that these requirements were added
because of the short period of time in which the SDT drafted the Standard, and, thus, NextEra is
hopeful that once highlighted here that the SDT will quickly decide to delete the requirements as
they are inconsistent with current Standard drafting practices. These requirements are
inconsistent with both results based and P81 concepts, given that they are administrative in
nature and do little to promote reliability. While some may see these requirements as good
practices, adding them is no longer consistent with Standard drafting practices nor desired by
stakeholders. New Standards are to be clear, high quality, technically sound and results based.
Also, these requirements are similar to those that FERC recently indicated it would approve for
retirement in the P81 Notice of Proposed Rulemaking. Therefore, NextEra requests that these
requirements, noted below, be deleted. R2. Each Reliability Coordinator shall review its GMD
Operating Plan at least once every 36 calendar months from the last effective date. R4. Each
Transmission Operator and Balancing Authority shall review its GMD Operating Procedures at
least once every 36 calendar months from the last effective date.
PacifiCorp
No
PacifiCorp affirms that if the intent of a review of an entity’s GMD plans and procedures is to
improve the scientific understanding of GMDs, a more prudent requirement would be a
periodicity that is post-operative event based.In the absence of a GMD event, the 36-month
requirement is arbitrary and one that would likely be performed by an entity as a best business
practice.
DTE Electric
No
Please see previous comments from Questions 1, 2, and 3.
Entergy Services,
Inc.
No
R5 is an administrative requirement for which compliance may be unprovable. This requirement
(to have a copy of its GMD Operating Procedures in its Primary and Back-up Control Rooms) is
also redundant to PER-005, which requires a Job Task Analysis for every task performed by
System Operators. All administrative requirements should be deleted.
Electric Reliability
Council of Texas,
Inc.
No
Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain
and implement operations plan to mitigate GMD effects. Whether or not there is a hard copy, or
electronic copy for that matter, in the control room and/or the backup control centre is
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Organization
Yes or No
Question 4 Comment
unimportant and irrelevant. In order that the Responsible Entities implement the plan to comply
with the standard requirements, operatinbg personnel needs to be provided and have access to
the plan itself, regardless of where and how it is placed. We suggest removing R5.
Hydro One
Networks Inc.
No
Requirement R5 is of a purely administrative nature, not contributing to reliability. Suggest to
eliminate. Emphasis and focus should be in operating personnel training and awareness. If R5 is
kept in the standard, request to clarify the meaning of “prior to its implementation date.” We
believe it should be “prior to actions to implement the plan.” As written in could be
misinterpreted as prior to the standard effective date.
Arizona Public
Service Company
No
Requirement R5 is unnecessary and should be deleted altogether. This requirement is a process
and not a standard and it is not necessary to have a hard copy when an electronic copy could be
readily available. There is no reliability benefit to this requirement.
Pepco Holdings
Inc & Affiliates
No
Requirement R5 seems administrative in nature (similar to other Paragraph 81 requirements)
and seems duplicative of R3 which already requires implementation of the Operating Procedures
(i.e. implementation could include making operation personnel aware of the Operating
Procedure and having available). If a separate training requirement is developed, R5 would be
further redundant. Recommend that R5 be removed.Requirement R2 and R4 require applicable
entities to review their GMD Plans/Operating Procedures every 36-months. With solar cycles
having an average duration of about 11 years and the Plan and Operating Procedure being
potentially utilized 1-2 years during the peak years of the 11 year cycle, how was the 36 month
review criteria reached? Recommend changing to a 48 month review period which still allows
for 2-3 reviews during a 11 year solar cycle.
FirstEnergy
No
Requirements R2 & R4FirstEnergy questions the need for Requirement R2 and R4 which propose
an every 3-year review of GMD operating procedures. This is an administrative task and should
not be a reliability requirement subject to mandatory enforcement. The requirements do not
adhere to principles identified by the Par. 81 team and now being applied across all drafting
teams. Par 81 Criteria B1 Administrative which states "The Reliability Standard requirement
requires responsible entities to perform a function that is administrative in nature, does not
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Organization
Yes or No
Question 4 Comment
support reliability and is needlessly burdensome." Additionally, an upcoming draft revision to
the NUC-001 standard is proposing to remove a similar obligation in NUC-001 (R9.1.3). FERC’s
Order 779 did not suggest a need for the responsible entities to periodically update their GMD
Operating Procedures every 3-years. Rather in paragraph 39 the Commission states "While
responsible entities will develop and implement operational procedures, NERC can support their
efforts, for example, by identifying and sharing operational procedures found to be the most
effective. NERC should also periodically survey the responsible entities’ operational procedures,
offer recommendations based on lessons-learned and new research findings, and re-evaluate
whether modification to the Reliability Standards is warranted." It is our understanding that it’s
the ERO’s responsibility to reconsider whether or not more specific minimum GMD procedure
expectations should be codified in the standard at some future date. This could be done for
example during the 5-year review period of the standard and the NERC GMD Task Force could be
tasked with providing the review required of NERC and propose changes to the GMD standard if
needed.Requirements R5Requirement R5 indicates a need for the Operating Procedures to be
located at the primary and back-up control center facility. The intent of Requirement R5 is
already covered in standard EOP-008-1, R2. FirstEnergy recommends that Requirement R5 be
struck as a redundant obligation.
The United
Illuminating
Company
No
Requirements R2 and R4 t to review the plan is purely administrative. As the scientific
knowledge evelves R1 and R3 requires a plan to be designed to mitigate the effects of GMD.
American Electric
Power
No
Requirements R2 and R4 state that each applicable entity shall review its GMD Operating
Plan/Procedures every 36 months from the last *effective* date while Requirement 5 states that
the applicable entities shall have a copy of its GMD Operating Procedures in the control room(s)
prior to its *implementation* date. AEP recommends referencing the effective date only.R5
should be changed to state “...shall have a hard or electronic copy of its GMD Operating
Procedures...”
Northeast Power
Coordinating
No
The review interval specified in R2 and R4 is 36 months. A five year review would be more
appropriate given the length of the solar cycle.As R2 and R4 are currently written, they are purely
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69
Organization
Yes or No
Council
Question 4 Comment
administrative and do nothing to improve or ensure reliability. R1 requires the GMD Operating
Plan be maintained which infers the need to review on a periodic basis.Requirement R5 also is
administrative, does not contribute to reliability, and can be eliminated. Suggest to eliminate the
wording “All procedures should be at the primary and backup control center as part of normal
business”. Emphasis and focus should be on operating personnel training and awareness.If it is
decided to keep R5 in the Standard, request clarificiation of the meaning of “prior to its
implementation date.” It should be “prior to actions to implement the plan.” As written it could
be misinterpreted as prior to the Standard’s effective date.
SPP Standards
Review Group
No
To address timing issues in R5, we suggest inserting the word ‘current’ between the ‘a’ and ‘copy’
and deleting the phrase ‘so that it is available to its operating personnel prior to its
implementation date’. R1 would then readEach Transmission Operator shall have a current copy
of its GMD Operating Procedures in its primary control room and any applicable backup control
rooms. For consistency with EOP-005, we would suggest that the VRF for R5 be reduced to Low.
This is an administrative requirement and does not merit a Medium VRF.Additionally, we wonder
why the Reliability Coordinator is not required to have a copy of its GMD Operating Plan in its
primary and backup control centers.
Great River
Energy
No
With NERC’s Relaibilibity Assurance Initiative (RAI), the P81 initiative and the work performed by
the Independent Expert Review Project, R2 & R4 are administrative in nature and suggest the
drafting team remove these two requirements. Similarly, R5 is also in administrative and is
redundant with R3 because R3 has an implementation requirement. Per the P81 NOPR, CIP-0033, R4 which required the cyber security policy be available to all personnel with CCA
responsibilities, has been approved to be retired.
Oklahoma Gas &
Electric
Yes
We agree with the language of these three requirements, however, we believe that the
Violation Risk Factor should be LOWER, not Medium for these documentation related
requirements.
ReliabilityFirst
Yes
1)Requirement R2 - ReliabilityFirst recommends clarifying the term “effective date” by including
the following language “of its GMD Operating Plan” at the end of the requirement.
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Organization
Yes or No
Question 4 Comment
ReliabilityFirst suggests the following for the SDTs consideration: "Each Reliability Coordinator
shall review its GMD Operating Plan at least once every 36 calendar months from the last
effective date [of its GMD Operating Plan]."2) Requirement R4 - ReliabilityFirst recommends
clarifying the term “effective date” by including the following language “of its GMD Operating
Plan.” ReliabilityFirst suggests the following for the SDTs consideration: "Each Transmission
Operator and Balancing Authority shall review its GMD Operating Procedures at least once every
36 calendar months from the last effective date [of its GMD Operating Procedures]."
Idaho Power
Company
Yes
Agree in General. Propose adding Generator Operator to R4, M4, R5 and M5. Many of the other
standards are using a five year review cycle. The review requirement should also include a trigger
based on system upgrades or major changes to system topology.
NV Energy
Yes
Agree with the 36 month cycle of review; however, BA should be removed from R4.
Florida Municipal
Power Agency
Yes
Although FMPA agrees with a 3 year period, FMPA would prefer a requirement of once every 3
calendar years as opposed to 36 months to allow more flexibility in scheduling.Again, the BA
should not be an applicable entity.
Los Angeles
Department of
Water and Power
Yes
Periodic review is important. LADWP would like to know the basis for the time period of 36
months.
Los Angeles
Department of
Water and Power
Yes
Periodic review is important. LADWP would like to know the basis for the time period of 36
months.
PJM
Interconnection,
L.L.C.
Yes
PJM has signed onto SERC's comments.
Independent
Electricity System
Yes
Requirements R2 and R4 could easily be combined. Is there a specific reason why the Reliability
Coordinator is separated from the Transmittion Operator and the Balancing Authority? The
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71
Organization
Yes or No
Operator
Question 4 Comment
wording in these two requirements is identical.
Northern
California Power
Agency
Yes
MRO NERC
Standards Review
Forum (NSRF)
Yes
SERC OC Review
Group
Yes
seattle city light
Yes
Emprimus LLC
and Volkmann
Consulting
Yes
Bonneville Power
Administration
Yes
JEA
Yes
Salt River Project
Yes
Western Area
Power
Administration
Yes
Western
Electricity
Yes
Yes, but I do not see that this is any different form complying with IRO-005-3 R3 except for the 36
month review cycle.
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Organization
Yes or No
Question 4 Comment
Coordinating
Council
Southern
Company
Yes
Bureau of
Reclamation
Yes
Colorado Springs
Utilities
Yes
Foundation for
Yes
Resilient Societies
CenterPoint
Energy
Yes
NIPSCO
Yes
American
Transmission
Company
Yes
LCRA
Transmission
Services Corp
Yes
Public Utility
District No. 2 of
Grant County,
Yes
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73
Organization
Yes or No
Question 4 Comment
WA
Ben Li Associates
Yes
Tri-State
Generation and
Transmission
Association, Inc.
Yes
Public Utility
District No.1 of
Snohomish
County
Yes
Oncor Electric
Delivery
Complany LLC
Yes
Minnkota Power
Cooperative, INC.
Yes
City of Austin dba
Austin Energy
Yes
Texas Reliability
Entity
Yes
Duke Energy
Yes
Northeast
Utilities
Yes
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Organization
Yes or No
Xcel Energy
Yes
American Public
Power
Association
Yes
Farmington
Electric Utility
System
Yes
Luminant
Generation
Yes
Consideration of Comments: Project 2013-03 | August 30, 2013
Question 4 Comment
75
5. If you have any other comments on this draft Standard that you haven’t already mentioned above, please provide them here.
Summary Consideration: The drafting team thanks all who responded to Question 5. The drafting team reviewed all comments and has
incorporated changes in response to suggestions from those comments into a revised version of EOP-010-1. A summary of comments
and the drafting team's response is provided below:
One commenter suggested an appendix be included with the standard to support information sharing and learning. The
drafting team believes this activity should be addressed through existing mechanisms and not through additional requirements.
The NERC Events Analysis program supports the industry’s post-event review and learning needs, and this includes emerging
risks. Additionally the GMD Task Force provides a forum for best practices and learning that can include post-event reporting
and analysis from participating entities.
Commenters stressed the value of studies and analysis; some recommended that the ordering of stage 1 and stage 2 in the
SAR and FERC Order should be reversed. The drafting team agrees that detailed studies such as those that may be required in
stage 2 will provide a better assessment of risk and more appropriate and effective mitigation measures. However, there are
prudent measures to mitigate risk from a GMD event that can be implemented without detailed system impact studies. The
drafting team believes EOP-010-1 provides a reliability benefit as written and meets the directives in FERC Order No. 779.
One commenter suggested changes to language used in the effective date section of the standard. NERC Legal worked with a
representative of the Canadian Electricity Association to revise the language to ensure it appropriately reflects the current
mechanisms for making standards effective in each of the Canadian provinces.
Suggestions for an alternate approach to meeting the directives through existing standards. Some commenters disagreed with
the drafting team's approach to meeting the stage 1 directives contained in FERC Order No. 779 with a new standard.
Commenters argued for modifications to existing standards or a response to the FERC directive that points to existing
requirements to avoid duplicating requirements. The drafting team agrees that existing standards including IRO-014, EOP-001,
and TOP-004 could be modified to meet the directives in the order. However, the drafting team recognized the challenges of
developing and successfully balloting the stage 1 standards within the deadlines established by the order and chose to create a
single new standard. We respect the view of some stakeholders that an alternate approach would have been preferred. The
drafting team also agrees that existing requirements that are applicable at all times provide some mitigation during GMD events;
however, this approach does not meet the directives in Order No. 779. The drafting team did not write prescriptive requirements
for real-time actions to mitigate GMD events, which would duplicate TOP-001. Furthermore, planning and policy requirements
contained in TOP-002, TOP-004, and EOP-001 do not meet the specific directives of FERC Order No. 779 as written.
A commenter supported the technical work but considered the posting of the draft standard for ballot simultaneously with
the SAR to be a violation of NERC Rules of Procedure. The scope of the current project was set forth in detail by the Federal
Consideration of Comments: Project 2013-03 | August 30, 2013
76
Energy Regulatory Commission in Order No. 779 and there is a January 2014 deadline associated with the project. The decision
to simultaneous post the SAR and the proposed Reliability Standard with a ballot conducted during the last ten days of that
comment period was approved by the NERC Standards Committee. We respect your disagreement with this process decision and
hope that you will continue to participate in the development of this standard.
Comments provided about draft GMD Task Force Planning Application Guide were considered out of scope for Stage 1
standards. Specific comments on the GMD Task Force Operating Procedure template were reviewed and did not affect the
development of EOP-010-1 requirements but are valid points to consider in developing an entity's Operating Procedures.
Several suggestions for changes to wording were provided, considered, and incorporated into revisions when the drafting team
agreed that they provided an improvement. The drafting team did not agree with comments suggesting the removal of the Longterm Planning Time Horizon from Requirements R1 and R3 because the required action, which is the development of Operating
Plans, Processes, or Procedures, could take place years before a space weather event necessitating carrying out the actions in an
entity’s Operating Process or Procedure.
The drafting team does not intend to produce a separate Guidelines and Technical Basis section for EOP-010-1, but has posted
technical resources on the project page. The GMD Task Force page also contains technical references and task force products
including the 2012 GMD Report.
Several commenters stated that Requirement R5 is not needed. As noted above in response to Question 4, Requirement R5
was determined to be unnecessary for reliability and deleted in the revision since Requirements R1 and R3 require that
applicable entities implement their GMD Operating Plans, Procedures, and Processes.
Organization
Question 5 Comment
Oklahoma Gas & Electric
While we understand the good intentions of FERC in Order No. 779, we feel that industry’s time would
be better spent pursuing Reliability initiatives that were focused on more pressing, well-documented
threats to reliability, particularly as it relates to entities that are located in more southerly regions of the
continent.
Manitoba Hydro
(1) Background - for clarity, consider replacing the words “can lead to” with [may result in]. (2) Purpose
- for clarity, consider replacing the purpose section of the standard with the following sentence: “To
[ensure plans, operating procedures, and resources are maintained and available] to mitigate the effects
of geomagnetic disturbance (GMD) [emergencies on the bulk electric system.]” (3) M2 - consider
revising the measure as follows:”Each Reliability Coordinator shall have evidence [showing] that it has
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Organization
Question 5 Comment
reviewed its GMD Operating Plan within the timeframe of Requirement R2. [Acceptable evidence could]
include a dated review signature sheet or revision history.” (4) 3.1, 3.2 and 3.3 - for completeness, start
the sentance with [A listing of the]. (5) M4 - consider revising the measure as follows: “Each Transmission
Operator and Balancing Authority shall have evidence [showing] that it has reviewed its GMD Operating
Procedures within the timeframe of Requirement R4. [Acceptable evidence could include] a dated review
signature sheet or revision history.” (6) Table of Compliance Elements, R2, Low, Medium, High VSL insert the word [last] before the words “effective date” for consistency with Requirement R2. (7) Some
entities may reduce exports to neighbors as a mitigating strategy. This method, determined to be the
ideal action, based on system studies, may be perceived as potentially impacting neighbouring entities.
What level of coordination would be required or appropriate to permit the curtailment of exports?
ACES Standards
Collaborators
(1) We are concerned that implementation of an operating procedure for GMD may require the removal
a number of transformers and could be viewed as causing a burden to neighboring systems contrary to
TOP-001-1a R7. TOP-001-1a R7 compels the TOP and GOP to not remove facilities from service if it would
burden neighboring systems unless there is not time for notification and coordination. Could the
requirement to write an operating procedure for responding to GMD events be viewed as allowing time
for coordination and notification particularly if the TOP documented in their plan to notify their RC? If
EOP-010 persists, TOP R7.3 should be modified to clarify that a TOP and GOP may not have sufficient time
during an extreme GMD event to make appropriate notifications and the requirement for the RC to have
an operating plan will be viewed as this coordination. (2) The Long-term Planning Time Horizon for each
requirement should be removed. The Long-Term Planning Horizon covers a period of one year or longer.
An operating procedure or plan will cover the Real-Time Operations horizon or Operations Planning
horizon at best. By NERC Glossary definition, an operating plan, process or procedure will not cover the
Long-Term Planning horizon. An operating procedure lists the specific steps that should be taken by
specific operating positions. An operating process includes steps that may be selected based on “Realtime conditions”. A operating plan contains operating procedures and processes. (3) Part 3.1 in R3 is
unnecessary because NERC already designates MISO and WECC RC to monitor the space weather through
the National Oceanic and Atmospheric Administration (NOAA) Space Weather Prediction Center (SWPC).
MISO communicates this information to the Eastern and ERCOT Interconnections through reliability
coordinator information system (RCIS) and WECC communicates it to the Western Interconnection as
documented in a NERC alert. There is not a need to codify a process that is already in place and works
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Organization
Question 5 Comment
effectively.
Western Area Power
Administration
: WAPA and Reclamation also believe Generator Operators should have a role in developing Operating
Procedures that will affect their equipment.
ReliabilityFirst
1) Requirement R5 - To be consistent with the language in the other requirements within the standard,
ReliabilityFirst recommends changing the term “implementation date” to “effective date.” ReliabilityFirst
offers the following for the SDTs consideration: "Each Transmission Operator and Balancing Authority
shall have a copy of its GMD Operating Procedures in its primary control room and any applicable backup
control rooms so that it is available to its operating personnel prior to its [effective] date." 2)
Consideration for new Requirement R6 - ReliabilityFirst recommends including a new Requirement R6
which would require adjacent Reliability Coordinators to share their respective GMD Operating Plans.
During a GMD event, it can span multiple Reliability Coordinator areas and ReliabilityFirst believes the
adjacent Reliability Coordinators should be aware of each other’s GMD Operating Plans. 3) VSL
Requirement R2 - The date ranges between the VSLs are not inclusive. The VSLs need to reflect "...but
less than or equal to..." language. ReliabilityFirst offers the following as an example “Lower” modified
VSL for the SDTs consideration: "The Reliability Coordinator reviewed its GMD Operating Plan more than
36 months, but less than [or equal to] 39 months, since the effective date."4) VSL Requirement R4 - The
date ranges between the VSLs are not inclusive. The VSLs need to reflect "...but less than or equal to..."
language. ReliabilityFirst offers the following as an example “Lower” modified VSL for the SDTs
consideration: "The responsible entity reviewed its GMD Operating Procedures and submitted them for
approval more than 36 months, but less than [or equal to] 39 months, since the last effective date."
Tri-State Generation and
Transmission Association,
Inc.
1. Tri-State believes a 6 month implementation period isn't appropriate for this. This implementation
period requires the RC to develop the Operating Plan and the TOP/BA to develop the Operating
Procedures at the same time. The TOP/BA needs time to ensure their procedures are in line with the RC's
Operating Plan so the implementation dates need to be staggered. 2. Tri-State also believes Stage 1 and
Stage 2 should be reversed. Developing, maintaining, and implementing a plan without first conducting
assessments and determining the risk is illogical. The Operating Plans should be based on the results
shown of the assessments.3. There is a lack of evidence showing major damage and widespread outages
due to a geomagnetic disturbance. There should be more studies performed before creating a Reliability
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Organization
Question 5 Comment
Standard in order to better determine the actual necessity of one. 4. Currently, Tri-State believes that a
guidance document would be a better solution to address the risk of potential geomagnetic
disturbances.5. Tri-State believes all non-BES transformers should be excluded regardless of high side
voltage. In addition any transformer with a delta primary winding should be excluded regardless of the
high side voltage.
Independent Electricity
System Operator
1. Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain and
implement operations plan to mitigate GMD effects. Whether or not there is a hard copy, or electronic
copy for that matter, in the control room and/or the backup control centre is unimportant and irrelevant.
In order that the Responsible Entities implement the plan to comply with the standard requirements,
operating personnel needs to be provided and have access to the plan itself, regardless of where and how
it is placed. We suggest removing R5.If Requirement R5 was to be retained, we suggest adding “Reliability
Coordinator” after “Transmission Operator” and “Balancing Authority”. We believe that Reliability
Coordinators should also have a copy of their GMD Operating Procedures in their primary and backup
control rooms. The current Requirement R5 does not include the Reliability Coordinator. 2. The proposed
Implementation Plan may conflict with Ontario regulatory practice with respect to the effective date of
the standard. It is suggested that this conflict be removed by moving the last part in the effective date
“,or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.”
to the end of the first sentence immediately after “by applicable regulatory authorities”.The same change
should be made to the first bullet under the Effective Dates Section of the Implementation Plan.
Ben Li Associates
1. Requirement R5 is not needed. The objective is that each Responsible Entity develop, maintain and
implement operations plan to mitigate GMD effects. Whether or not there is a hard copy, or electronic
copy for that matter, in the control room and/or the backup control centre is unimportant and irrelevant.
In order that the Responsible Entities implement the plan to comply with the standard requirements,
operating personnel needs to be provided and have access to the plan itself, regardless of where and how
it is placed. We suggest removing R5.2. GMDs are an emerging issue. There is nothing in this standard
that enables information sharing and learning. The RC plan and BA/TOP procedures should include what
sensing information is in the field and the general reporting that such information gathering is done when
GIC symptoms are observed. There should also be information collected following major solar events
that is evaluated by the NERC technical committees. This should not be codified in the requirements, but
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Organization
Question 5 Comment
in an administrative appendix or an activity to be included in events analysis.
Salt River Project
A general comment on the Solar Cycle. It seems that the timing of the peak of the solar cycle might
require more frequent review of plans and procedures.  
Los Angeles Department
of Water and Power
Also, lacking is a clear statement that a directive from the RC (that GMD level X procedures are being
invoked) needs to act as a signal that the market is suspended for the duration of the directive. During
such GMD events, Grid Reliability will depend on the ability to redispatched generation to accommodate
new conditions and operating limits. A means of establishing appropriate prices for power and
Transmission rights should be established in advance and agreed to by all parties as a condition of GMD
Operating Plan approval.
Los Angeles Department
of Water and Power
Also, lacking is a clear statement that a directive from the RC (that GMD level X procedures are being
invoked) needs to act as a signal that the market is suspended for the duration of the directive. During
such GMD events, Grid Reliability will depend on the ability to redispatched generation to accommodate
new conditions and operating limits. A means of establishing appropriate prices for power and
Transmission rights should be established in advance and agreed to by all parties as a condition of GMD
Operating Plan approval.
Bonneville Power
Administration
BPA agrees that operational procedures should be put in place but they will not have sufficient analysis of
the full impact of certain actions due to certain technologies not being available at this point. Specifically,
the reactive and thermal impacts of GMD on transformers.
CenterPoint Energy
CenterPoint Energy is hopeful that the SDT will agree with CenterPoint Energy’s suggested changes. With
CenterPoint Energy’s suggested changes, we believe this standard can be reasonably applied throughout
North America. If not, we believe the proposed standard is problematic for regions that have little or no
GMD-related risk and ask that the SDT consider a proposal to exclude such regions from applicability.
CenterPoint Energy understands that such a proposal would be subject to the Commission’s review and
approval but the FERC Order is clear that the Commission understands that there are different risks in
different regions and the Commission does not endorse or order a “one-size-fits-all” approach.
CenterPoint Energy believes candidate regions to exclude from these requirements would potentially
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Organization
Question 5 Comment
include ERCOT, SERC, and FRCC. However, to re-iterate our main point, we believe this standard could be
applied to all regions, even those regions with minimal GMD-related risk, if CenterPoint Energy’s
proposed changes are accepted. Even for those regions that have more GMD-related risk than other
regions, CenterPoint Energy believes it is problematic and, at best, inefficient, for each and every
Transmission Operator and Balancing Authority in such regions to attempt to develop individual
Operating Procedures intended to collectively enhance the reliability of the region as a whole.
Colorado Springs Utilities
Comments on Requirement 1: o In need to include a requirement for the RC to acquire and disseminate
space weather information to the applicable entities within their footprint.Comments on Requirement 3:
o From the glossary; Operating Procedure (in part): "The steps in an Operating Procedure should be
followed in the order in which they are presented"; Operating Process (in part): "An Operating Process
includes steps with options that may be selected depending upon Real-time conditions." The language in
the Standard will be what is audited to, notwithstanding what any individual utility may titles their
documents. The actions which may be required during a GMD event are far better presented in an
Operating Process (as defined) than an Operating Procedure (as defined). There is no way that a TOP
could follow the exact same step-by-step procedure for all GMD eventualities, but that is what the
"Operating Procedure" term demands.Comments on Requirement R3.1: o Need to eliminate the
requirement to acquire space weather information in R3.1, and have it a part of the information that the
RC would disseminate to ensure consistency and coordination from the RC.Comments on Implementation
Plan:1. Need to ensure that RC develops and disseminates their plan 1st with time included to
incorporate RC plan into BA/TOP/GOP plans.2. Implementation period needs to be extended from 6
months to 12 months.
Northeast Utilities
Comments on the Geomagnetic Disturbance Operating Procedure Template:Transmission Operator:
Information and Indications:Triggers: External: Watch, Warning and Alert K index numbers are too low. Kindex is known to be an unreliable predictor of GMD severity, however it makes no sense to activate
procedures below K7.Triggers Internal: System-wide/ equipment-level: Parameters mentioned could be
abnormal due to other causes. There should be corroborating evidence cause is GMD before entering
procedure.Actions Available to the Operator: Should specify that the actions are not limited to those
listed.Long lead-time: Safe system posturing (only if supported by study): Should specify the level of
study. For example, this should mean a coordinated earth conductivity/ system study across a wide area
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Question 5 Comment
to ensure that other entities are not negatively impacted- not just a state estimator study.Remove shunt
reactors: some systems auto switch reactors. These (and capacitors) should be left in auto so that they
can respond to voltage swings.Day-of-event: Increase situational awareness: These require being able to
corellate the observed parameters to equipment/ system effect before taking actionsPrepare for
unplanned capacitor bank/SVC/HVDC tripping: Should add that multiple installations should be evaluated
as a single contingency.Real-time actions: Safe system posturing (only if supported by study):Selective
load shedding: No guidance is provided as to how this could help in a GMD.Manually start fans/pumps on
selected transformers: Due to the hazard of potential catastrophic failure from static electrification
caused when oil temperature is below 50 C, this section should not be mentioned.System reconfiguration
(only if supported by study): Should specify the level of study. For example, this should mean a
coordinated earth conductivity/ system study across a wide area to ensure that other entities are not
negatively impacted- not just a state estimator study.Return to normal operation: Why is any time limit
mentioned at all?
SPP Standards Review
Group
Delete the phrase ‘and submit(ted) them for approval’ from the VSLs in R4. R4 does not require approval.
Duke Energy
Duke Energy believes that “Same Day Operations” is a more appropriate time horizon for R1 and R3.
El Paso Electric Company
EPE generally supports stage 1 of Project 2013-03: Geomagnetic Disturbance Mitigation. EPE is concerned
with the short implementation period of six calendar months following applicable regulatory approval
and would like to see a 1 year long implementation period instead.
Farmington Electric Utility
System
FEUS appreciates the work by the SDT team to allow entities flexibility when developing their operating
procedures for mitigating GMD. The flexibility allows for entities to develop the plan that works with their
system
Southern Company
For R3.1, to address potential confidential data issues, the weather data utilized should be publicly
available . We recommend changing R3.1 as follows:R3.1 The steps or tasks for the acquisition and
dissemination of publicly available space weather information to its System Operators.
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NextEra Energy
For the same reasons provided in response to question number #4 (P81 -- administrative in nature),
NextEra requests that the following requirement be deleted: R5. Each Transmission Operator and
Balancing Authority shall have a copy of its GMD Operating Procedures in its primary control room and
any applicable backup control rooms so that it is available to its operating personnel prior to its
implementation date.
Public Utility District No. 2
of Grant County, WA
GCPD is concerned about the implementation period being sufficient to allow the RC to develop and
implement a GMD Operating Plan AND afford adequate time to ensure that each TO and BA within its
region the ability to develop, maintain and implement GMD Operating Procedures that are coordinated
with the RC's GMD Operating Plan. Six (6) months is not sufficient time to allow development and
coordination within the region.
Great River Energy
GRE agrees with ACES, The Long-term Planning Time Horizon for each requirement should be removed.
The Long-Term Planning Horizon covers a period of one year or longer. An operating procedure or plan
will cover the Real-Time Operations horizon or Operations Planning horizon at best. By NERC Glossary
definition, an operating plan, process or procedure will not cover the Long-Term Planning horizon. An
operating procedure lists the specific steps that should be taken by specific operating positions. An
operating process includes steps that may be selected based on “Real-time conditions”. A operating plan
contains operating procedures and processes.
Arizona Public Service
Company
Implementation time for BA and TOP should have 6 additional months than the implementation time for
Reliability coordinator. This is to allow coordination wiht Reliability Coordinator’s procedures affecting BA
and TOP.Requirement R1, 1.2 should have the word “all” deleted. It does not serve any specific purpose
and could become unnecessarily burdensome.
American Electric Power
In the VSL matrix, R4 states that “the responsible entity reviewed its GMD Operating Procedures and
submitted them for approval....”. Requirement 4, as stated, does not require approval for the Operating
Procedures, therefore the words “and submitted them for approval” should be deleted from all four VSLs
for R4.
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Luminant Generation
Luminant has voted Negative as the posting and balloting of the GMD proposed standard did not follow
the NERC Rules of Procedure. Luminant appreciates the technical work of the Ad Hoc group but believes
the standard should have been posted for comments only, instead of being posted for balloting.
Texas Reliability Entity
Many new Standards have a Guidelines and Technical Basis section as part of the Standard. Would the
SDT consider creating a Guidelines and Technical Basis section?
LCRA Transmission
Services Corp
none
National Rural Electric
Cooperative Association
(NRECA)
NRECA is does not believe that it is necessary to develop a separate GMD standard to address requiring
Operating Procedures for GMD events. Criteria for addressing such events can easily be added to existing
standards that require entities to have Operating Procedures. Suggesting a new standard that has similar
requirements as existing standards does not adhere to the spirit of the P81 initiative to eliminate
unnecessary duplicative requirements. Examples of requirements that could be revised to address GMD
events are: IRO-014-1 R1 requires the RC to have operating procedures, processes or plans for activities
that require notification or exchange of information with other Reliability Coordinators. TOP-004-2 R6.1
requires the TOP to have policies and procedures for monitoring and controlling voltage levels and
reactive power flows. R5 - NRECA agrees that it is reasonable to require that a copy of an applicable
entity’s GMD Operating Procedures is in its primary control room and any applicable backup control
rooms so that it is available to its operating personnel prior to its implementation date. In the Time
Horizon designation for the requirements of this standard, the “Long Term Planning” horizon should be
removed. As written, this standard addresses Operating Procedures to address Real-time events not
those that meet the criteria for a “Long Term” event.
City of Austin dba Austin
Energy
Overall, AE has voted negative because there is an abundance of cleanup work necessary. AE asks the SDT
to consider the comments above as well as the following points:(1) The SDT should more carefully
consider the wording for the applicability of transformers. During the webinar, someone asked if the
intent was to cover only BES tranformers and Mark Olsen answered in the affirmative. As written, the
BES definition considers the low-side voltage (greater than or equal to 100 kV), whereas the Applicability
section of EOP-010-1 considers only the high-side voltage. There could be transformers that are 69/230
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Question 5 Comment
kV that would not be BES Elements but would bring in a TOP or BA given the way 4.1.2 and 4.1.3 are
currently written. Additionally, the SDT should consider transformers with high and low-side voltages
greater than 100kV but excluded from the BES based on a documented exclusion or exception.(2) Given
the requirement to “develop, maintain and implement” in R1 and R3, the SDT should consider adding in
the same day operations time horizon to cover the "implement" action.(3) The SDT should clarify what is
intended by “implement” in R1 and R3. During the webinar, the response to this question was unclear.
SDTs on other recent projects (COM-003-1, for example) have gone to great lengths to define what is
meant by "implement." RSAWs often state it means to include in your company’s body of operating
procedures. Without explanation, a CEA might interpret implement as follow your Plan/Procedure exactly
as written. The industry needs to know the SDT’s intent.(4) Change the word “all” to “applicable” before
the phrase “Transmission Operators and Balancing Authorities” in R1 part 1.2.(5) The SDT should move
the requirement regarding space weather (currently R3 part 3.1) to R1 so the RC can, in its coordination
role, ensure that input data is consistent and applicable to its Region.
Emprimus LLC and
Volkmann Consulting
R5 should be applicable to RC also.
The United Illuminating
Company
Requirement R5 to make the operating plan available in the control center is administrative. Reliability
requires the plan to be implemented as described in requirement R1. VRF for R1 and R3 are Medium
since an entity failure to implement the GMD operating plan may lead to cascade. VRF for R2, R4, and R5
should be Low. R2, R4, and R5 are purely administrative. The entity is required to have Operating Plans
that mitigate the effects of GMD a review of the operating plan is a secondary activity to developing,
maintaining, and implementing an operating plan.
Minnkota Power
Cooperative, INC.
See NSRF Comments
Western Electricity
Coordinating Council
Six Month implementation period is not adequate
Sacramento Municipal
SMUD also has concerns with the implementation period and questions whether or not six months is
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Utility District
adequate time for the BA and TOP to develop the required GMD Operating Procedures and for the RC to
develop the required Plan to coordinate those GMD Operating Procedures. SMUD also encourages the
SDT to consider the GMD threshold application to be raised to 300+kV,and also encourages the Project
2013-03 Standard Drafting Team to consider the comments submitted by Florida Municipal Power
Agency (FMPA) related to applicability of the standard.
City of Tallahassee
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark
studies” as required in Stage 2. It would seem appropriate to have the studies first in order to write the
procedures as required in Stage 1. The Stage 2 could remain with the incorporation of equipment for the
mitigation of the GIC.The white paper for the 200kV threshold has not been made available as was
promoted on the July 30 webinar. How can we vote when the reference is not available?
City of Tallahassee
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark
studies” as required in Stage 2. It would seem appropriate to have the studies first in order to write the
procedures as required in Stage 1. The Stage 2 could remain with the incorporation of equipment for the
mitigation of the GIC.The white paper for the 200kV threshold has not been made available as was
promoted on the July 30 webinar. How can we vote when the reference is not available?
City of Tallahassee Electric Utility
Stage 1 requires an Operating Procedure to protect the BES, however, we do not have the “benchmark
studies” as required in Stage 2. It would seem appropriate to have the studies first in order to write the
procedures as required in Stage 1. The Stage 2 could remain with the incorporation of equipment for the
mitigation of the GIC.The white paper for the 200kV threshold has not been made available as was
promoted on the July 30 webinar. This reference is valuable to entity wishing to make an informed vote.
Transmission Agency of
Northern California
TANC appreciates the performance flexibility that has been built into the current draft of this standard,
but has concerns regarding the approximately six month implementation period between its approval
and effective date. Of particular concern is the ability for each Reliability Coordinator to ensure
coordination and compatibility between its GMD Operating Plan and the GMD Operating Procedures for
all Transmission Operators and Balancing Authorities in its footprint during such an abbreviated period.
As this initiative moves forward, TANC requests that NERC continue to carefully consider the scope of
entities and assets that will be subject to this and subsequent standards so that the costs borne by the
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Question 5 Comment
industry are commensurate with the anticipated benefit to reliability.
FirstEnergy
The comments are supported by the following GMD standard ballot body members representing
FirstEnergy: Bill Smith, Segment 1 Transmission Owners; Cindy Stewart, Segment 3 Load Serving Entities;
Doug Hohlbaugh, Segment 4 Transmission Dependent Utilities; Ken Dresner, Segment 5 Electric
Generators and Kevin Querry, Segment 6 Brokers, Aggregators, and Marketers.
Xcel Energy
The current IRO-005-3.1a R3 requires RCs to notify TOPs and BAs of certain GMD events. Consider
deleting this requirement in IRO-005-3.1a as part of this implementation plan and add something in this
standard (EOP-010) requiring RCs to make that notification. The pending approval of IRO-005-4 removed
the explicit requirement, but development history indicates that it considers GMD to have an Adverse
Reliability Impact that would require RC notification to entities.
Foundation for Resilient
Societies
The Foundation for Resilient Societies has concerns that the NERC Planning Application Guide, developed
without full public access to the related model assumptions, will mis-characterize geomagnetic latitudes
with geographic latitudes; and will result in scientifically invalid assumptions that the NERC modeled
"operating procedures" will suffice without need for hardware protections. For our Foundation review of
the Draft NERC GMD Planning Application Guide, our review dated August 9, 2013, see:
http://resilientsocieties.org/images/Resilient_Societies_Comments_on_GMD_Planning_Application_Guid
e_Final.pdf.
Hydro One Networks Inc.
There is a GMD related pre-existing requirement in IRO-005-3.1a R3. It seems, given the extensive
Operating Plans proposed in EOP-010-1, that R3 in IRO-005-3.1a can be retired. This should be considered
by the GMDTF.The proposed Implementation Plan may conflict with Ontario regulatory practice with
respect to the effective date of the standard. It is suggested that this conflict be removed by moving the
last part in the effective date “,or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.” to the end of the first sentence immediately after “by applicable
regulatory authorities”.The same change should be made to the first bullet under the Effective Dates
Section of the Implementation Plan.
Northeast Power
There is a GMD related pre-existing requirement in IRO-005-3.1a R3. The implementation plan is not clear
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Question 5 Comment
Coordinating Council
regarding the retirement of the requirement. It would seem, given the extensive Operating Plans
proposed in EOP-010-1, that R3 in IRO-005-3.1a can be retired. This should be considered by the
GMDTF.Simpler wording would make the Standard easier to understand. Every plan will be different
depending upon a wide range of factors affecting GMD mitigation; equipment types and inventory,
location, system configuration and topography, latitude, ground characteristics, etc. Suggest the
following simplifying wording changes to Requirement R3:R3. Each Transmission Operator and Balancing
Authority shall develop, maintain, and implement GMD Operating Procedures. At a minimum, the
Operating Procedures shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning,
Operations Planning] 3.1. The steps or tasks for the acquisition and dissemination of space weather
information to its System Operators. 3.2. The steps or tasks to be employed by System Operators that are
coordinated with its Reliability Coordinator's GMD Operating Plan. 3.3 The predetermined trigger
conditions for initiating and terminating steps or tasks in the Operating Procedure.To be consistent with
the terminology in other standards, suggest changing the wording the Applicability Section to:4.1.2
Balancing Authority with a Balancing Authority Area that includes transformers with high voltage
terminals connected at 200kV and above.4.1.3 Transmission Operator with a Transmission Operator Area
that includes transformers with high voltage terminals connected at 200kV and above.The wording of the
Purpose should be changed to "To mitigate the risk of instability, uncontrolled separation, and Cascading
in the Bulk-Power System as a result of geomagnetic disturbance (GMD) events by developing,
maintaining and implementing Operating Plans and Operating Procedures." The Purpose as written
should state what GMD affects. It also only addresses the implementation of the Operating Procedures
but does not address the development and maintenance aspect, nor does it address the Operating Plans.
Northern California Power To suumarize:I will vote no on the initial ballot per comments I have submitted; however that does not
Agency
mean I am opposed to this standard. I do believe GMD is an issue that even though it is low frequency
can have an reliabiilty impact on the BES or BPS.I believe the SDT needs to address the IRO-005-3 R3
concern I have discussed. If I were to guess the reason for EOP-010-1, it would be to replace a pretty
loose requirement in IRO-005-3 R3. If this is the case then give more direction and guidance in the new
standard per the guidance document that NERC provided
Bureau of Reclamation
WAPA and Reclamation also believe that Generator Operators should have a role in developing Operating
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Question 5 Comment
Procedures that will affect their equipment.
Ameren
We believe GMD is a regional issue and therefore a NERC Standard is not necessary. We believe that
studies need to be completed before considering a new NERC Standard. In addition, an entity cannot
develop operating plans and procedures based on unstudied GMD conditions. After the initial
assessments of potential impacts of GMD on BES reliability is complete, then appropriate (if necessary)
plans and procedures can then be developed and if necessary a standard could then be drafted based on
results of the studies.
MRO NERC Standards
Review Forum (NSRF)
Would like clarification of the statement “last effective date” in the Table of Compliance Elements, Rows
2 and 4. Change the sentence to the following:”The responsible entity reviewed its GMD Operating
Procedures and submitted them for approval more than 36 months, but less than 39 months, since the
last effective date of the procedures”
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Draft 2
Stage 1 Standard
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EOP-010-1 — Geomagnetic Disturbance Operations
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee accepted the Standard Authorization Request (SAR) submitted by
the Geomagnetic Disturbance Task Force (GMD TF) and approved Project 2013-03
(Geomagnetic Disturbance Mitigation) on June 5, 2013.
2. The draft standard was posted for a 45-day formal comment period and initial ballot from
June 26, 2013 through August 12, 2013. The SAR was posted for informal comment during
the same period.
Description of Current Draft
This is the second posting of the proposed standard. It is posted for a 45-day formal comment
period and additional ballot.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Ballot
September 2013
Final ballot
October 2013
BOT adoption
November 2013
Draft 2: September 3, 2013
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EOP-010-1 — Geomagnetic Disturbance Operations
Effective Dates
The first day of the first calendar quarter that is six months after the date that this standard is
approved by an applicable governmental authority or as otherwise provided for in a jurisdiction
where approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the standard
shall become effective on the first day of the first calendar quarter that is six months after the
date this standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Version History
Version
1
Date
TBD
Action
Project 2013-03
Change
Tracking
N/A
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
Draft 2: September 3, 2013
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EOP-010-1 — Geomagnetic Disturbance Operations
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Plans, Processes, and Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes a
power transformer with a high side wye-grounded winding with terminal
voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to adversely impact the
reliable operation of interconnected transmission systems. 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
protection system Misoperation, the combination of which may result in voltage
collapse and blackout.
B. Requirements and Measures
R1. Each Reliability Coordinator shall develop,
maintain, and implement a GMD Operating Plan
that coordinates GMD Operating Procedures
within its Reliability Coordinator Area. At a
minimum, the GMD Operating Plan shall
include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning, Operations
Planning, Same-day Operations, Real-time
Operations]
1.1 A description of activities designed to
mitigate the effects of GMD events on the
reliable operation of the interconnected
transmission system within the Reliability
Coordinator Area.
Rationale and supporting
information for Requirement R1:
An Operating Plan is implemented
by carrying out its stated actions.
Coordination is intended to ensure
that operating procedures are not in
conflict with one another.
An Operating Plan is maintained
when it is kept relevant by taking
into consideration system
configuration, conditions, or
operating experience, as needed to
accomplish its purpose.
1.2 A process for the Reliability Coordinator to review the GMD Operating
Procedures of Transmission Operators in the Reliability Coordinator Area.
M1. Each Reliability Coordinator shall have a GMD Operating Plan meeting all the
provisions of Requirement R1; evidence such as a review or revision history to
indicate that the GMD Operating Plan has been maintained; and evidence to show that
the plan was implemented as called for in its GMD Operating Plan, such as dated
operator logs, voice recordings, or voice transcripts.
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EOP-010-1 — Geomagnetic Disturbance Operations
R2. Each Reliability Coordinator shall disseminate
forecasted and current space weather information
as specified in the Reliability Coordinator's GMD
Operating Plan. [Violation Risk Factor: Medium]
[Time Horizon: Same-day Operations, Real-time
Operations]
M2. Each Reliability Coordinator shall have evidence
such as dated operator logs, voice recordings,
transcripts, or electronic communications to
indicate that forecasted and current space weather
information was disseminated as stated in its
GMD Operating Plan.
R3. Each Transmission Operator shall develop,
maintain, and implement an Operating
Procedure or Operating Process to mitigate the
effects of GMD events on the reliable operation
of its respective system. At a minimum, the
Operating Procedure or Operating Process shall
include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning, Operations
Planning, Same-day Operations, Real-Time
Operations]
3.1. Steps or tasks to receive space weather
information.
3.2. System Operator actions to be initiated
based on predetermined conditions.
3.3. The conditions for terminating the
Operating Procedure or Operating Process.
M3. Each Transmission Operator shall have a GMD
Operating Procedure or Operating Process
meeting all the provisions of Requirement R3;
evidence such as a review or revision history to
indicate that the GMD Operating Procedure or
Operating Process has been maintained; and
evidence to show that the Operating Procedure or
Operating Process was implemented as called for
in its GMD Operating Procedure or Operating
Process, such as dated operator logs, voice
recordings, or voice transcripts.
Rationale and supporting
information for Requirement R2:
Requirement R2 replaces IRO-0053.1a, Requirement R3. IRO-005-4
has been adopted by the NERC
Board and filed with FERC, and
will retire IRO-005-3.1a
Requirement R3. If EOP-010-1
becomes effective prior to the
retirement of IRO-005-3.1a,
Requirement R2 shall become
effective on the first day following
retirement of IRO-005-3.1a.
Space weather forecast information
can be used for situational
awareness and safe posturing of the
system. Current space weather
information can be used for
monitoring progress of a GMD
event.
The Reliability Coordinator is
responsible for disseminating space
weather information to ensure
coordination and consistent
awareness in its Reliability
Coordinator Area.
Rationale and supporting
information for Requirement R3:
An Operating Procedure or
Operating Process is implemented
by carrying out its stated actions.
An Operating Procedure or
Operating Process is maintained
when it is kept relevant by taking
into consideration system
configuration, conditions, or
operating experience, as needed to
accomplish its purpose.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
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EOP-010-1 — Geomagnetic Disturbance Operations
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) 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 Reliability Coordinator and Transmission Operator shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity 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 CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Draft 2: September 3, 2013
Page 5 of 8
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning,
Operations
Planning,
Same-day
Operations,
Real-time
Operations
Medium The Reliability
Coordinator had a
GMD Operating Plan,
but failed to maintain
it.
R2
Same-day
Operations,
Real-time
Operations
Medium N/A
R3
Long-term
Planning,
Operations
Planning,
Same-day
Medium The Transmission
Operator had a GMD
Operating Procedure
or Operating Process,
but failed to maintain
Draft 2: September 3, 2013
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan failed
to include one of the
required elements as
listed in Requirement
R1, parts 1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
N/A
N/A
The Reliability
Coordinator failed to
disseminate forecasted
and current space
weather information as
specified in the
Reliability
Coordinator's GMD
Operating Plan.
The Transmission
Operator's GMD
Operating Procedure
or Operating Process
failed to include one
The Transmission
Operator's GMD
Operating Procedure or
Operating Process
failed to include two or
The Transmission
Operator did not have
a GMD Operating
Procedure or Operating
Process
OR
The Reliability
Coordinator failed to
implement a GMD
Operating Plan within
its Reliability
Coordinator Area.
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EOP-010-1 — Geomagnetic Disturbance Operations
Operations,
Real-time
Operations
Draft 2: September 3, 2013
it.
element in
Requirement R3, parts
3.1 through 3.3.
more elements in
Requirement R3, parts
3.1 through 3.3.
OR
The Transmission
Operator failed to
implement its GMD
Operating Procedure or
Operating Process.
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EOP-010-1 — Geomagnetic Disturbance Operations
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EOP-010-1 — Geomagnetic Disturbance Operations
D. Regional Variances
None.
E. Interpretations
None.
Draft 2: September 3, 2013
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EOP-010-1 — Geomagnetic Disturbance Operations
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee accepted the Standard Authorization Request (SAR) submitted by
the Geomagnetic Disturbance Task Force (GMD TF) and approved Project 2013-03
(Geomagnetic Disturbance Mitigation) on June 5, 2013.
2. The draft standard was posted for a 45-day formal comment period and initial ballot from
June 26, 2013 through August 12, 2013. The SAR was posted for informal comment during
the same period.
Description of Current Draft
This draft is the firstsecond posting of the proposed standard and. It is being done in conjunction
with the posting of the SARposted for this projecta 45-day formal comment period and
additional ballot.
Anticipated Actions
Anticipated Date
30-day Formal Comment Period
June 2013
45-day Formal Comment Period with Parallel Initial Ballot
AugustSeptember
2013
Successive Ballot (if needed)
September 2013
RecirculationFinal ballot
NovemberOctober
2013
BOT adoption
November 2013
Draft 1: Date 6/19/132: September 3, 2013
Page 1 of 11
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EOP-010-1 — Geomagnetic Disturbance Operations
Effective Dates
The first day of the first calendar quarter that is six months beyondafter the date that this
standard is approved by an applicable regulatory authorities. In those jurisdictionsgovernmental
authority or as otherwise provided for in a jurisdiction where regulatory approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by
an applicable governmental authority is not required, the standard shall become effective on the
first day of the first calendar quarter that is six months beyondafter the date this standard is
approvedadopted by the NERC Board of Trustees, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities. provided for in that jurisdiction.
Version History
Version
1
Date
TBD
Action
Project 2013-03
Change
Tracking
N/A
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
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EOP-010-1 — Geomagnetic Disturbance Operations
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Plans, Processes, and Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Balancing Authority with a Balancing Authority Area that includes any
transformer with high side terminal voltage greater than 200 kV
4.1.34.1.2
Transmission Operator with a Transmission Operator Area that
includes anya power transformer with a high side wye-grounded winding
with terminal voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to negativelyadversely
impact the reliable operation of interconnected transmission systems. 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
protection system Misoperation, the combination of which can lead tomay result in
voltage collapse and blackout.
B. Requirements and Measures
R1. Each Reliability Coordinator shall develop,
maintain, and implement a GMD Operating Plan
to coordinatethat coordinates GMD Operating
Procedures within its Reliability Coordinator
Area. At a minimum, the GMD Operating Plan
shall include: [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning, Operations
Planning], Same-day Operations, Real-time
Operations]
Rationale and supporting information
for Requirement R1: An Operating Plan
is implemented by carrying out its stated
actions.
Coordination is intended to ensure that
operating procedures are not in conflict
with one another.
An Operating Plan is maintained when it
is kept relevant by taking into
consideration system configuration,
conditions, or operating experience, as
needed to accomplish its purpose.
1.1
A description of activities designed to
mitigate the effects of GMD events on the
reliable operation of the interconnected
transmission system within the Reliability
Coordinator Area.
1.2
A process for the Reliability Coordinator to determine thatreview the GMD
Operating Procedures of all Transmission Operators and Balancing Authorities
in the Reliability Coordinator Area are coordinated and compatible. .
M1. Each Reliability Coordinator shall have a GMD Operating Plan meeting all the
provisions of Requirement R1; and evidence such as a review or revision history to
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EOP-010-1 — Geomagnetic Disturbance Operations
indicate that the GMD Operating Plan has been maintained; and evidence to show that
the plan was implemented such as correspondence with Transmission Operators and
Balancing Authoritiesas called for in its GMD Operating Plan, such as dated operator
logs, voice recordings, or voice transcripts.
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EOP-010-1 — Geomagnetic Disturbance Operations
R2.
Each Reliability Coordinator shallEach Reliability
Coordinator shall review its GMD Operating Plan at least
once every 36 calendar months fromdisseminate forecasted
and current space weather information as specified in the
the last effective date. Reliability Coordinator's GMD
Operating Plan. [Violation Risk Factor:
Medium][Violation Risk Factor: Medium] [Time
Horizon:[Time Horizon: Long-term Planning,Same-day
OperationsOperations Planning], Real-time Operations]
M2. Each Reliability Coordinator shall have evidence that it has
reviewed its GMD Operating Plan within the timeframe of
Requirement R2 such as a datedEach Reliability
Coordinator shall have evidence such as dated review
signature sheetoperator logs, voice recordings, transcripts,
or or revision history.electronic communications to indicate
that forecasted and current space weather information was
disseminated as stated in its GMD Operating Plan.
R3. Each Transmission Operator and Balancing Authority shall
develop, maintain, and implement an Operating
ProceduresProcedure or Operating Process to mitigate the
effects of GMD events on the reliable operation of its
respective system. At a minimum, the Operating
ProceduresProcedure or Operating Process shall include:
[Violation Risk Factor: Medium] [Time Horizon: Longterm Planning, Operations Planning, Same-day Operations,
Real-Time Operations]
3.1. The stepsSteps or tasks for the acquisition and
dissemination ofto receive space weather information
to its.
3.2. System Operators.
3.2. The steps or tasksOperator actions to be employed by
System Operators that are coordinated with its
Reliability Coordinator's GMD Operating Plan to
mitigate the effectsinitiated based on the system from
GMD events.
3.3
The predetermined trigger conditions.
3.3
The conditions for initiating and terminating steps or
tasks in the Operating Procedure or Operating Process.
Rationale and supporting
information for Requirement
R2: Requirement R2 replaces
IRO-005-3.1a, Requirement R3.
IRO-005-4 has been adopted by
the NERC Board and filed with
FERC, and will retire IRO-0053.1a Requirement R3. If EOP-0101 becomes effective prior to the
retirement of IRO-005-3.1a,
Requirement R2 shall become
effective on the first day following
retirement of IRO-005-3.1a.
Space weather forecast
information can be used for
situational awareness and safe
posturing of the system. Current
space weather information can be
used for monitoring progress of a
GMD event.
The Reliability Coordinator is
responsible for disseminating
space weather information to
ensure coordination and consistent
awareness in its Reliability
Coordinator Area.
Rationale and supporting
information for Requirement
R3: An Operating Procedure or
Operating Process is implemented
by carrying out its stated actions.
An Operating Procedure or
Operating Process is maintained
when it is kept relevant by taking
into consideration system
configuration, conditions, or
operating experience, as needed to
accomplish its purpose.
M3. Each Transmission Operator and Balancing Authority shall have a GMD Operating
ProceduresProcedure or Operating Process meeting all the provisions of Requirement
R3.
R4. Each Transmission Operator and Balancing Authority shall review its GMD
Operating Procedures at least once every 36 calendar months from the last
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EOP-010-1 — Geomagnetic Disturbance Operations
effective date. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning, Operations Planning]
M4. Each Transmission Operator and Balancing Authority shall have; evidence that it has
reviewed its GMD Operating Procedures within the timeframe of Requirement R4 such
as a dated review signature sheet or revision history.
R5. Each Transmission Operator and Balancing Authority shall have a copy of its
GMD to indicate that the GMD Operating Procedure or Operating Procedures in
its primary control room and any applicable backup control rooms so that it is
availableProcess has been maintained; and evidence to its operating personnel
prior to its implementation date. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning, Operations Planning]
M5. Each Transmission Operator and Balancing Authority shall have hard copies or
electronic copies of its GMD Operating Procedure available for inspectionshow that the
Operating Procedure or Operating Process was implemented as stated. called for in its
GMD Operating Procedure or Operating Process, such as dated operator logs, voice
recordings, or voice transcripts.
R2.
Each Reliability Coordinator shall review its GMD Operating Plan at least once every
36 calendar months from the last effective date. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning, Operations Planning]
M2. Each Reliability Coordinator shall have evidence that it has reviewed its GMD
Operating Plan within the timeframe of Requirement R2 such as a dated review
signature sheet or revision history.
R4. Each Transmission Operator and Balancing Authority shall review its GMD Operating
Procedures at least once every 36 calendar months from the last effective date.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations
Planning]
M4. Each Transmission Operator and Balancing Authority shall have evidence that it has
reviewed its GMD Operating Procedures within the timeframe of Requirement R4 such
as a dated review signature sheet or revision history.
R5. Each Transmission Operator and Balancing Authority shall have a copy of its GMD
Operating Procedures in its primary control room and any applicable backup control
rooms so that it is available to its operating personnel prior to its implementation date.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations
Planning]
M5. Each Transmission Operator and Balancing Authority shall have hard copies or
electronic copies of its GMD Operating Procedure available for inspection as stated.
C. Compliance
1.
Compliance Monitoring Process
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EOP-010-1 — Geomagnetic Disturbance Operations
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) 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 Reliability Coordinator, and Transmission Operator and Balancing Authority
shall keep data or evidence to show compliance as identified below unless
directed by its Compliance Enforcement AuthorityCEA to retain specific
evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for 3three years.
If a responsible entity 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 AuthorityThe CEA 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 Violation InvestigationsInvestigation
Self-Reporting
Complaints Text
Complaint
1.4. Additional Compliance Information
None
Draft 1: Date 6/19/132: September 3, 2013
Page 7 of 11
Table of Compliance Elements
R#
Time Horizon
VRF
Violation Severity Levels
Lower VSL
R1
R2R
2
Long-term
Planning,
Operations
Planning, Same-day
Operations, Realtime Operations
Long-term
Planning,Same-day
OperationsOperatio
ns Planning, Realtime Operations
Medium
MediumMediu
m
The Reliability
Coordinator
failed to maintain
had a GMD
Operating Plan,
but failed to
maintain it.
N/A
The Reliability
Coordinator
reviewed its
GMD Operating
Plan more than
36 months, but
less than 39
months, since the
effective date.
The Reliability
Coordinator
reviewed its GMD
Operating Plan
more than 39
months, but less
than 42 months,
since the effective
date.
N/A
Draft 1: Date 6/19/132: September 3, 2013
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan
failed to include
one of the required
elements as listed
in Requirement R1,
parts 1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
The Reliability
Coordinator
reviewed its GMD
Operating Plan
more than 42
months since the
effective date.
The Reliability
CoordinatorThe
Reliability
Coordinator did not
review itsfailed to
disseminate
forecasted and
current space
weather
information as
specified in the
Reliability
Coordinator's GMD
Operating
N/A
OR
The Reliability
Coordinator failed
to implement a
GMD Operating
Plan within its
Reliability
Coordinator Area.
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EOP-010-1 — Geomagnetic Disturbance Operations
PlanGMD
Operating Plan.
R3
R4
Long-term
Planning,
Operations
Planning, Same-day
Operations, Realtime Operations
Medium
Long-term
Medium
Planning,
Operations Planning
Draft 1: Date 6/19/132: September 3, 2013
The responsible
entityTransmissio
n Operator had a
GMD Operating
Procedure or
Operating
Process, but
failed to maintain
GMD Operating
Proceduresit.
The responsible
entity reviewed
its GMD
Operating
Procedures and
submitted them
for approval more
than 36 months,
but less than 39
months, since the
last effective
The responsible
entity'sTransmissio
n Operator's GMD
Operating
ProceduresProcedu
re or Operating
Process failed to
include one
element in
Requirement R3,
parts 3.1 through
3.3.
The responsible
entity'sTransmissio
n Operator's GMD
Operating
ProceduresProcedu
re or Operating
Process failed to
include two or
more elements in
Requirement R3,
parts 3.1 through
3.3.
The responsible
entityTransmission
Operator did not
have a GMD
Operating
ProceduresProcedu
re or Operating
Process
The responsible
entity reviewed its
GMD Operating
Procedures and
submitted them for
approval more than
39 months, but less
than 42 months,
since the last
effective date.
The responsible
entity reviewed its
GMD Operating
Procedures and
submitted them for
approval more than
42 months since the
last effective date.
The responsible
entity did not
review its GMD
Operating
Procedures and
submit them for
approval.
OR
The responsible
entityTransmission
Operator failed to
implement its
GMD Operating
ProceduresProcedu
re or Operating
Process.
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EOP-010-1 — Geomagnetic Disturbance Operations
date.
R5
Long-term
Medium
Planning,
Operations Planning
Draft 1: Date 6/19/132: September 3, 2013
N/A
N/A
N/A
The responsible
entity did not have
copies of its GMD
Operating
Procedures in its
primary control
room and all
backup control
rooms if applicable.
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EOP-010-1 — Geomagnetic Disturbance Operations
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
EOP-010-1 — Geomagnetic Disturbance Operations
D. Regional Variances
None.
E. Interpretations
None.
Draft 1: Date: 6/19/132: September 3, 2013
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
Retirements
None
Revisions to Glossary Terms
None
Applicable Entities
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side wye-grounded winding with terminal voltage greater than 200 kV
Conforming Changes to Other Standards
None
Effective Dates
Requirement R2 of EOP-010-1 replaces Requirement R3 of IRO-005-3.1a. IRO-005-4 has been adopted
by the NERC Board and filed with FERC in Docket Number RM13-15-000, and will retire Requirement
R3 of IRO-005-3.1a:
IRO-005-3.1a, Requirement R3:
R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
EOP-010-1 replaces this requirement with the following:
EOP-010-1, Requirement R2:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information as specified in the Reliability Coordinator's GMD Operating Plan.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Therefore, to ensure responsibility for disseminating space weather information in the Reliability
Coordinator Area is maintained while avoiding duplicative requirements being enforceable at the same
time, EOP-010-1 shall become effective as follows:
In those jurisdictions where regulatory approval is required:
By the first day of the first calendar quarter that is six months beyond the date that this
standard is approved by applicable governmental authorities or as otherwise made effective
pursuant to the laws of applicable to these authorities.
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
In those jurisdictions where regulatory approval is not required:
By the first day of the first calendar quarter that is six months beyond the date this standard
is adopted by the NERC Board of Trustees or as otherwise made effective pursuant to the
laws of applicable governmental authorities.
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan – August 30, 2013
2
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
Retirements
None
Revisions to Glossary Terms
None
Applicable Entities
Reliability Coordinator
Balancing Authority with a Balancing Authority Area that includes any transformer with high side
terminal voltage greater than 200 kV
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side wye-grounded winding with terminal voltage greater than 200 kV
Conforming Changes to Other Standards
None
Effective Dates
Requirement R2 of EOP-010-1 replaces Requirement R3 of IRO-005-3.1a. IRO-005-4 has been adopted
by the NERC Board and filed with FERC in Docket Number RM13-15-000, and will retire Requirement
R3 of IRO-005-3.1a:
IRO-005-3.1a, Requirement R3:
R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
EOP-010-1 replaces this requirement with the following:
EOP-010-1, Requirement R2:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information as specified in the Reliability Coordinator's GMD Operating Plan.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Therefore, to ensure responsibility for disseminating space weather information in the Reliability
Coordinator Area is maintained while avoiding duplicative requirements being enforceable at the same
time, EOP-010-1 shall become effective as follows:
In those jurisdictions where regulatory approval is required:
By the first day of the first calendar quarter, six calendar months following applicable
regulatory approval. that is six months beyond the date that this standard is approved by
applicable governmental authorities or as otherwise made effective pursuant to the laws of
applicable to these authorities.
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
In those jurisdictions where regulatory approval is not required:
By the first day of the first calendar quarter that is six calendar months followingbeyond the
date this standard is adopted by the NERC Board of Trustees approval.or as otherwise made
effective pursuant to the laws of applicable governmental authorities.
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan – June 26, 2012August 30, 2013
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Unofficial Comment Form
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1 (Geomagnetic Disturbance Operations)
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by 8:00 p.m. ET Friday,
October 18, 2013.
If you have questions please contact Mark Olson at [email protected] or by telephone at 404-4469760.
The project page may be accessed by clicking here.
Background Information
The Project 2013-03 Geomagnetic Disturbance (GMD) Mitigation Standard Drafting Team posted an initial
draft of the Standard EOP-010-1 (GMD Operations) for comment from June 26 to August 12, 2013. The
drafting team has revised the standard based on stakeholder recommendations that the drafting team
considered appropriate. The following is a summary of changes the drafting team has made:
A new Requirement R2 has been added to the standard, which would require RCs to disseminate
space weather forecast information to TOPs in the Reliability Coordinator Area (RCA). IRO-0053.1a Requirement R3 currently provides this obligation. However, NERC Board has approved IRO005-4 which would result in retirement of the requirement. The new Requirement R2 in EOP-010-1
will maintain the RCs responsibility for providing space weather forecast information. The
implementation plan includes guidance to avoid a situation where both IRO-005-3.1a Requirement
R3 and EOP-010-1 Requirement R2 are effective at the same time.
In response to stakeholder comments that certain Requirements met Paragraph 81 criteria,
administrative requirements for reviewing GMD Operating Plans and Procedures within a 36month period and for having a copy in the control room were removed.
Several changes in language were made to improve clarity.
Applicability:
o Balancing Authorities (BA) have been removed from the applicable functional entities
because there are no additional steps or tasks for a BA to perform beyond their normal
balancing functions to mitigate GMD events. The BA is not expected to initiate specific
mitigating actions during a GMD event and would instead respond to the direction of the
Transmission Operator (TOP) and Reliability Coordinator (RC). Existing standards provide
the required authority for action. A whitepaper with the drafting team's analysis is posted
on the project page.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
o The applicable TOP has been clarified to include only those that operate power
transformers with a high side wye-grounded winding with terminal voltage greater than
200 kV. This applicability statement describes the functional entity in terms of the assets
that they operate, which could include non-BES assets. The applicability statement is not
intended to define equipment to be protected by the Operating Procedures. The drafting
team views 200 kV as the minimum network voltage for which a reliability benefit can be
expected from the application of GMD Operating Procedures. A whitepaper with the
drafting team's analysis is posted on the project page.
Although some stakeholders suggested that Generator Operators (GOP) be added to the standard as
applicable entities, the drafting team maintains that a GOP's Operating Procedures specifically to mitigate
the effects of GMD would need to be supported by an equipment-specific study and might require the use
of GMD monitoring equipment. Because it is not reasonable to assume that all GOPs have such studies or
monitoring equipment, GOPs have not been added to EOP-010-1. Consistent with Order No. 779,
vulnerability assessments and mitigation plans will be addressed in stage 2 of Project 2013-03. Generator
Owners (GO) and GOPs will be considered for applicability with stage 2. A whitepaper with the drafting
team's analysis supporting the applicability of EOP-010-1 is posted on the project page.
Some stakeholders also commented that the six-month implementation period was too short. The
drafting team is sympathetic to the challenge of completing the necessary coordination in a six-month
time period. However this implementation period was suggested in FERC Order No. 779 and the drafting
team lacks strong justification for a specific longer period.
This posting solicits comment on the revised EOP-010-1 standard. The standard responds to FERC Order
No. 779, directing NERC to develop Stage 1 Standard(s) that require applicable entities to develop and
implement Operating Procedures. Stage 1 Standard(s) must be filed by January 2014.
Questions on EOP-010-1
1. The drafting team has revised EOP-010-1 in response to stakeholder comments. Changes include
removing the BA from applicability, clarifying applicability for TOPs, adding a Requirement for RCs to
disseminate space weather information, removal of administrative requirements that do not benefit
reliability, and clarifying changes to the language of requirements and measures. Do you agree that the
revised standard correctly addresses the Stage 1 directives of Order No. 779 and is acceptable? If you do
not agree or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes
No
Comments:
Unofficial Comment Form
Project 2013-Geomagnetic Disturbance Mitigation
2
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2. Do you agree that the VRFs and VSLs support the reliability objectives of the standard and meet FERC
and NERC guidelines? If you do not agree or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
3. The Implementation Plan provides conditions for determining when the Requirements in EOP-010-1
become effective in each jurisdition. Do you agree with the Implementation Plan as written? If you do not
agree or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes
No
Comments:
4. If you have any other comments for the drafting team to consider that you haven’t already mentioned,
please provide them here:
Comments:
Unofficial Comment Form
Project 2013-Geomagnetic Disturbance Mitigation
3
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Standards Authorization Request Form
Standards Authorization Request Form
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
EOP-010-1 Geomagnetic Disturbance Operations
TPL-007-1 Transmission System Planned Performance During
Geomagnetic Disturbances
Date Submitted:
SAR Requester Information
Name:
Kenneth Donohoo, Oncor
Organization:
Chair, Geomagnetic Disturbance Task Force
Telephone:
NA
E-mail:
NA
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.):
To mitigate the risk of instability, uncontrolled separation, and Cascading in the Bulk-Power System 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.
Industry Need (What is the industry problem this request is trying to solve?):
While the impacts of space weather are complex and depend on numerous factors, space weather has
demonstrated the potential to disrupt the operation of the Bulk-Power System. A technical discussion of
the effects of geomagnetic disturbances on the Bulk-Power System and recommended actions for NERC
and the industry is provided in the NERC 2012 GMD Report prepared by the GMD Task Force. During a
GMD event, geomagnetically-induced current (GIC) flow in transformers may cause half-cycle
1
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Standards Authorization Request Form
SAR Information
saturation, which can increase absorption of Reactive Power, generate harmonic currents, and cause
transformer hot spot heating. Harmonic currents may cause protection system Misoperation leading to
the loss of Reactive Power sources. The combination of these effects from GIC can lead to voltage
collapse.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will develop requirements for registered entities to employ strategies that
mitigate risks of instability, uncontrolled separation and Cascading in the Bulk-Power System caused by
GMD in two stages as directed in Order 779:
1. Stage 1 standard(s) will require applicable registered entities to develop and implement
Operating Procedures with predetermined and actionable steps to take prior to and during GMD
events which take into account entity-specific factors that can impact the severity of GMD
events in the local area. The Stage 1 standard(s) may also include associated training
requirements for System Operators or development of training requirements may be deferred to
Stage 2.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going
assessments of the potential impact of benchmark GMD events on their respective system as
directed in Order 779. The Stage 2 standard(s) must identify benchmark GMD events that
specify what severity GMD events applicable registered entities must assess for potential
impacts. If the assessments identify potential impacts from benchmark GMD events, the
Standard(s) will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of benchmark GMD events.
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 standards development project will respond to the directives in FERC Order 779 in the timeframe
required by the Order and draw upon the technical products of the GMD Task Force Phase 2 Project and
other relevant information. The GMD Task Force Phase 2 Project addresses the recommendations in
the 2012 GMD Report and is focused on improving the capabilities of industry to assess GMD risk and
develop appropriate mitigation strategies.
2
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Standards Authorization Request Form
SAR Information
Operating Procedures are the first stage in the Standards project to manage risks associated with GMD
events with accompanying training requirements to be addressed in Stage 1 or 2 as determined by the
Standards Drafting Team. Specifically, the project will require owners and operators of the Bulk-Power
System to develop and implement Operating Procedures and accompanying operator training which
may include:
Procedures for acquiring and disseminating forecasting information and warning messages from
the space weather forecasting community to the System Operators;
Predetermined and actionable steps for System Operators to take prior to and during a GMD
event that are tailored to the registered entity's assessment of entity-specific factors such as
geography, geology, and system topology;
Procedures to notify and coordinate with interconnected registered entities for effective action;
Restoration procedures for applicable elements that may be impacted;
Minimum training requirements for System Operators; and
Criteria for discontinuing the use of Operating Procedures at the conclusion of a GMD event.
The second stage of the project will require applicable registered entities to conduct initial and periodic
assessments of the risk and potential impact of benchmark GMD events to the Bulk-Power System and
develop strategies to mitigate the risk of instability, uncontrolled separation, and Cascading.
The definition of benchmark GMD events will be based on reviewed technical analysis.
Periodic update of the assessments will be required to account for new Facilities and
modifications to existing Facilities. It is expected that assessments will also consider new
information and the use of new or updated tools, including new research on GMDs and the ongoing work of the NERC GMD Task Force.
The Standard(s) will require Planning Coordinators and Reliability Coordinators to review plans
addressing the potential impact of benchmark GMD events in order to provide a wide-area
perspective. The Standard Requirements for plans will be supported by reviewed technical
analysis, with consideration of the directives in FERC Order 779.
When both stages have been completed as required by FERC Order 779, all directives in the Order will
have been addressed.
3
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Standards Authorization Request Form
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.
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.
4
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Standards Authorization Request Form
Reliability Functions
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.
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
Enter
(yes/no)
Yes
Yes
Yes
5
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Standards Authorization Request Form
Reliability and Market Interface Principles
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.
Yes
Related Standards
Standard No.
PER-005-1, R3
Explanation
Training on GMD events and mitigation procedures will be added to this
requirement as a specific element in required operator training unless included in
a separate GMD standard.
Related SARs
SAR ID
Explanation
6
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Standards Authorization Request Form
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
The intent of the project is to develop continent-wide requirements that allow responsible entities to
tailor operational procedures or strategies based on the responsible entity's assessment of entityspecific factors such as geography, geology, and system topology. However, the need for regional
variances will be researched throughout the proposed project and may be supported by analysis
required to develop stage 2 Standard(s).
7
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Network Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators and Transmission Operators with networks
that contain power transformers with high side grounded wye windings above 200 kV. The drafting team
concluded that this is the minimum network voltage for which a reliability benefit can be expected from
the application of GMD Operating Procedures. This lower-bound threshold is consistent with operating
experience and modeling guidance provided in the literature, as explained below.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779.
Justification
Because transmission line resistance decreases by a factor of 10 from 69 kV to 765 kV and lower voltage
lines tend to be shorter (115 kV lines are typically less than 15 miles in length), the resulting
geomagnetically-induced current (GIC) generated by lines rated less than 200 kV are significantly less than
those of higher voltages and are typically ignored in GIC analysis. Conversely, using a voltage threshold
higher than 200 kV, such as 345 kV, for a lower-bound threshold could potentially create a reliability gap
by excluding a portion of the network that can be significantly affected by GMD. Results of sensitivity
analysis conducted by the drafting team is presented in the appendix. It shows that the GIC contribution
from the 230 kV portion of the network can result in system impacts during a GMD event.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Definition Considerations
Key parameters in the definition of a network for assessing GMD impacts are:
• Transformer grounding and core construction
o Only wye-grounded power transformer windings provide a path for GIC
o Transformer core construction (e.g, single-phase, three-phase, autotransformer) has an
effect on the magnitude of var absorption and generated harmonics. Single-phase
transformers are more susceptible to half-cycle saturation due to GIC relative to threephase 3-leg units; however, the var absorption in 3-legged three-phase core units cannot
be neglected.
o Regardless of core construction, all grounded wye transformers have an effect in the
distribution of GIC in the network
• System topology, including geographical orientation
• Resistance values of the elements of the DC network used to evaluate GIC distribution within the
network
o Transmission line resistances per unit length increase as the voltage level decreases (see
typical values in Table 1). (With the resistances shown in Table 1, the maximum neutral
GIC contributed by a single 230 kV circuit is of the order of 30 A, as opposed to 75 A for a
single 345 kV circuit.)
Selection of a network where the cut off is selected on the basis of wye-grounded power
transformers with HV terminals > 200 kV
•
•
•
Almost all peer-reviewed studies on the effects of GIC include networks > 200 kV [1-13].
When lower voltage levels are included, the effects of including network elements < 200 kV are in
most cases minimal [9]. (The Appendix shows an example of the effects of the inclusion/exclusion
of the 115 kV network.)
The absorption of reactive power in a saturated transformer depends on the system operating
voltage and GIC. It does not depend on the nameplate rating of the transformer. In the case of
single-phase power transformers, var absorption and harmonic generation are very insensitive to
air-core reactance [11].
TABLE 1
TYPICAL NETWORK RESISTANCES FOR DIFFERENT VOLTAGE-LEVEL POWER GRIDS IN NORTH AMERICA
System
Voltage Levels
(kV)
230
345
500
735
DC Resistances
of the
Transformers
(ohm)
0.692
0.356
0.195
0.159
Grounding
Resistances of
the Substations
(ohm)
0.563
0.667
0.125
0.258
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
DC Resistances
of the
Transmission
lines (ohm/km)
0.072
0.037
0.013
0.011
2
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•
Reactive power absorption of a saturated transformer is proportional to its HV voltage rating.
Transformers < 200 kV have a relatively lower influence in the reactive power balance of the
system (see Figure 1).
90
80
Q (Mvar)
70
60
500 kV
50
230 kV
40
115 kV
30
20
10
0
0
50
100
150
200
250
GIC (A/phase)
Figure 1: Reactive power absorption of a single-phase transformer vs. GIC
System Impact Considerations
A key element in a GMD event is the absorption of reactive power of high side wye-grounded
transformers experiencing half-cycle saturation.
•
•
•
In many jurisdictions bulk power transmission includes voltages > 200 kV. Tripping a transformer
with high side voltage > 200 kV or reconfiguring > 200 kV circuits can impose serious constraints on
operating limits; therefore, such operating scenarios must be considered in GMD impact studies.
Generator step-up transformers are typically situated at electrical end points of the network
where GIC tends to be highest. GSUs with high side voltages > 200 kV are not uncommon. On the
other hand, GIC injected by circuits < 200 kV is limited because of the higher resistances of GSUs
connected to < 200 kV networks
Autotransformers are often used in networks above > 200 kV. The flow of GIC depends heavily on
the relative resistances of various network elements and the geographical orientation of nearby
transmission lines [14]. Considering a 500/230 kV autotransformer with one 500 kV and one 230
kV circuit, modelling GIC flow without taking into consideration the 230 kV circuit results in GIC
overestimation between 20% and 30%. In a more complex configuration, the estimated GIC
ignoring the 230 kV circuits can over or underestimate GIC and the effects of GIC in transformers
significantly. The appendix shows an example of this effect.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
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•
•
From the point of view of GIC distribution in the network, transformer vulnerability is not a
consideration. Including only transformers with high side windings > 300 kV would result in
unrealistic GIC flow assessments (see Appendix)
In systems where the bulk transmission voltages are 230 kV and 500 kV, neglecting circuits rated
less than 300 kV would misrepresent GIC flows and var absorption, especially because GIC flowthrough in 500 kV autotransformers would be neglected (see Appendix).
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Appendix
This Appendix describes two examples where:
• The exclusion of 230 kV circuits at a station with 500/230 kV autotransformers cause significant
errors in the estimation of GIC effects.
• The inclusion/exclusion of the 161 kV and 115 kV networks in a large utility within the Eastern
Interconnect has minimal impact on the estimation of the effects of GIC in the system
Example 1: Exclusion of 230 kV circuits in a 500/230 kV transmission station
The distribution of GIC in a network, for a given geomagnetic latitude and earth structure, depends on a
number of factors such as resistances of various circuit elements, induced voltages and network topology.
There are times when a complex network topology can lead to non-intuitive results, such as the presence
of a series capacitor causing an increase of GIC in a transformer.
To illustrate, consider the topology of the circuits connected to Transmission Station (TS) shown in Fig. A1.
If a transmission circuit is sufficiently long it can be represented by a constant current source (since both
induced voltage and line resistance are proportional to line length). In the case of a 500 kV circuit, GIC
tends to be fairly constant for lengths > 150 km. A simplified representation is shown in Fig A2. The
station has several autotransformers which have been lumped into a single equivalent autotransformer.
The series capacitor bank is assumed to be out of service (bypassed).
Currents I1 and I2 represent the GIC contribution of the 500 kV circuits to the HV bus. Then,
I 3 = I1 − I 2
(A.1)
where I3 is the total contribution of the 500 kV circuits to the series winding. The total contribution to the
common winding is given by
Ig = I 3 + I 4 + I 5 + I 6 − I 7
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
(A.2)
5
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I1
Series capacitor
500 kV
230 kV
I4
230 kV
I5
I6
TS
230 kV
I2
I7
230 kV
500 kV
Fig. A1: HV transmission lines connecting to Essa TS.
I1
I4
I5
HV
I2
I3
I7
LV
Ig
I6
Fig. A2: Circuit representation of induced geoelectric fields and equivalent transformer representation.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
6
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Let us assume that the earth can be represented by a laterally-uniform earth model, and that the 500 kV
circuits are in the same or similar orientation geographically with the same resistance per unit length, so
that the injected GIC I1 and I2 are nearly identical (see Fig. A1). Then I3 will be small or zero and only the
230 kV circuits will contribute to the current in the transformer common winding Ig. If the 230 kV circuits
were excluded, (i.e., I4 = I5 = I6 = I7 = 0) then I3 = Ig would be very small and the estimated effects of GIC
on the autotransformer would be minimal.
If the 500 kV series capacitor bank in Fig. A1 is placed in service, then I1 = 0 and I2 = I3. The commonwinding GIC is now equal to the sum of the GIC contributed by the 230 kV circuits and the remaining 500
kV circuit. Depending on the relative values of the contributions, the net GIC through the transformer
may increase or decrease. Simulations show that in the network shown in Figure A1 when the series
capacitors are in service, the effective GIC through the transformer increases by a factor of 30. This is not
a general result, but rather a consequence of Kirchhoff’s current law and a particular system topology.
If the series capacitor bank is in service and the 230 kV circuits are not taken into consideration all the GIC
from the remaining 500 kV circuit would flow into the autotransformer and describe a completely
different situation from in terms of the saturation of the autotransformer.
The cases described above were simulated with a GIC analysis tool and summarized in Table A1. Note
that there are two 500/230 kV autotransformers in service in this simulation.
Table A1: Summary of the Effects of 230 kV Circuits in a Station
with Two 500/230 kV Autotransformers
Geoelectric
field
5 V/km
Transformer
GIC/phase
(A/phase)
I1 (A/phase)
I2 (A/phase)
Incremental
metallic hot spot
temperature (C°)
var absorption
(Mvar)
THD (%)
230 kV and
500 kV
500 kV Series
caps in service
230 kV and
500 kV
500 kV Series
caps bypassed
No 230 kV
500 kV Series
caps in service
No 230 kV
500 kV Series
caps bypassed
99.9
2.8
127
5.5
0
146.8
365
334
0
254
338
349
89
1.6
60
7.6
128
14
151
12.5
17
2.5
18
2.2
The conclusion from this example is that it is not always possible to make generalizations in a network of
relatively complex topology. While it is true that a series capacitor blocks GIC in the transmission line
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
7
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
where it is employed, it does not necessarily reduce GIC in system transformers. Furthermore, not taking
into account the effects of the 230 kV circuits in this network would lead to inaccurate conclusions, such
as a 33% underestimation of the hot spot temperature rise 1.
Example 2: Effects of the inclusion/exclusion of circuits below 200 kV
A portion of the Eastern Interconnect that contains 500 kV, 230 kV, 161 kV, and 115 kV facilities was
modeled using PowerWorld software. When the GIC contribution of the 161 kV and 115 kV circuits was
excluded, the effects on the network above 200 kV where found to be minimal. Table A2 summarizes the
effects of including/excluding GIC contributions from the 161 kV and 115 kV network assuming a 5 V/km
East-West geoelectric field. The differences in the results assuming a North-South geoelectric field are
very similar, and are not reproduced in here.
Table A2: GIC Effects on the Network Above 200 kV Assuming an
East-West 5 V/km Geoelectric Field
Including 115
kV
Maximum transformer GIC (A/phase)
134.65
Average transformer GIC (A/phase)
13.79
Maximum transformer var absorption 150.3
(Mvar)
Average transformer var absorption 7.16
(Mvar)
Minimum bus voltage (pu)
0.98204
Average bus voltage (pu)
1.01858
Total system var loss due to GIC (Mvar)
3,935
Excluding 115
kV
133.78
13.46
149.5
Difference
0.6 (%)
2.4 (%)
0.7 (%)
7.08
1.1 (%)
0.98548
1.01897
3,801
0.4 (%)
0.04 (%)
3.4 (%)
These results are consistent with observations made in peer-reviewed technical publications such as [9].
1
Hot spot heating was estimated using the methodology described in [15]
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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References
[1] Boteler, D., Bui-Van, Q., & Lemay, J. (1994). Directional sensitivity to geomagnetically induced currents of the
Hydro-Quebec 735 kV power system. Power Delivery, IEEE Transactions on, 9(4), 1963-1971.
[2] Boteler, D., Watanabe, T., Shier, R., & Horita, R. (1982). Characteristics of Geomagnetically Induced Currents in
the B. C. Hydro 500 kV System. Power Apparatus and Systems, IEEE Transactions on, PAS-101(6), 1447-1456.
[3] Mäkinen, T. (1992). Geomagnetically induced currents in the Finnish power transmission system. Helsinki,
Finland: Finnish Meteorological Institute.
[4] Mohan, N., Albertson, V., Speak, T., Kappenman, K., & Bahrman, M. (1982). Effects of Geomagnetically-Induced
Currents on HVDC Converter Operation. Power Apparatus and Systems, IEEE Transactions on, PAS-101(11), 44134418.
[5] Picher, P., Bolduc, L., Dutil, A., & Pham, V. (1997). Study of the acceptable DC current limit in core-form power
transformers. IEEE Transactions on Power Delivery, Vol 12, No1, 257-265.
[6] Pirjola, R. (2000). Geomagnetically induced currents during magnetic storms. Plasma Science, IEEE Transactions
on, 28(6), 1867-1873.
[7] Pirjola, R., & Boteler, D. (2006). Geomagnetically Induced Currents in European High-Voltage Power Systems.
Electrical and Computer Engineering, 2006. CCECE '06. Canadian Conference on (pp. 1263-1266). Ottawa, Canada:
IEEE.
[8] Pirjola, R., Liu, C.-m., & Liu, L.-g. (2010). Geomagnetically Induced Currents in electric power transmission
networks at different latitudes. Electromagnetic Compatibility (APEMC), 2010 Asia-Pacific Symposium on (pp. 699702). Beijing, China: IEEE.
[9] Prabhakara, F., Hannett, L., Ringlee, R., & Ponder, J. (1992). Geomagnetic effects modelling for the PJM
interconnection system. II. Geomagnetically induced current study results. Power Systems, IEEE Transactions on,
7(2), 565-571.
[10] Viljanen, A., Pirjola, R., Wik, M., Adam, A., Pracser, E., Sakharov, Y., et al. (2012). Continental scale modelling of
geomagnetically induced currents. J. Space Weather Space Clim., 3, A171-A1711.
[11] Walling, R., & Khan, A. (1991). Characteristics of transformer exciting-current during geomagnetic disturbances.
Power Delivery, IEEE Transactions on, 6(4), 1707-1714.
[12] Viljanen, A., & Pirjola, R. (1994). Geomagnetically Induced Currents in the Finnish High-Voltage
Power System: A Geophysical Review. Netherlands: Surveys in Geophysics, 15, 383-408.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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[13] Wik, M., Viljanen, A., Pirjola, R., Pulkkinen, A., Wintoft, P., & Lundstedt, H. (2008). Calculation of
Geomagnetically Induced Currents in the 400 kV Power Grid in Southern Sweden. Space Weather, Vol. 6,
S07005, 1-11.
[14] Overbye, T. J., et al, “Power Grid Sensitivity Analysis of Geomagnetically Induced Currents”, IEEE
Transactions on Power Delivery, 2013, Accepted for inclusion in a future issue, Digital Object Identifier
10.1109/TPWRS.2013.2274624.
[15] 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
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Functional Entity Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators (RC) and Transmission Operators (TOP) with
networks above 200 kV. This applicability is consistent with the NERC Functional Model and existing
standards where both entities are described as having responsibility and authority for reliable
transmission operations within their scope. The drafting team determined that Balancing Authorities (BA)
should not be among the applicable functional entities because there were no additional steps or tasks for
a BA to perform beyond their normal balancing functions to mitigate GMD events. The drafting team also
determined that Generator Operators (GOP) should not be among the applicable functional entities
because any Operating Procedures to mitigate the effects of GMD would need to be supported by an
equipment-specific study and is expected to require GMD monitoring equipment. Consistent with FERC
Order No. 779, vulnerability assessments and mitigation plans will be addressed in stage 2 of Project
2013-03 and applicability of stage 2 standards will be considered separately.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779. While the
applicability of the proposed stage 1 standard is limited to RCs and TOPs, other entities will be considered
for stage 2 as outlined in the Standards Authorization Request.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Justification for Applicable Functional Entities
Reliability Coordinator
The RC has responsibility and authority for reliable operation within the Reliability Coordinator Area
(RCA). The RC's scope includes a wide-area view with situational awareness of neighboring RCAs. The
NERC Functional Model states:
The Reliability Coordinator maintains the Real-time operating reliability of its Reliability
Coordinator Area and in coordination with its neighboring Reliability Coordinator's wide-area
view. The wide-area view includes situational awareness of its neighboring Reliability Coordinator
Areas. Its scope includes both transmission and balancing operations, and it has the authority to
direct other functional entities to take certain actions to ensure that its Reliability Coordinator
Area operates reliably.
The RC's authority is codified in IRO-001-1a which states:
R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions
to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions
shall be taken without delay, but no longer than 30 minutes.
R8. Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability
Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory
requirements. Under these circumstances, the Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity, or Purchasing-Selling Entity
shall immediately inform the Reliability Coordinator of the inability to perform the directive so that
the Reliability Coordinator may implement alternate remedial actions.
Including the RC as an applicable entity in EOP-010-1 provides the necessary coordination for planning
and real-time actions that is envisioned by the Functional Model and addresses Order No. 779 directives
to consider the coordination of Operating Procedures across regions by a functional entity with a widearea view.
Transmission Operator
Like the RC, the TOP has responsibility and authority for the reliable operation of the transmission system
within a specified area. According to the NERC Functional Model:
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
The Transmission Operator is responsible for the Real-time operating reliability of the transmission
assets under its purview, which is referred to as the Transmission Operator Area. The Transmission
Operator has the authority to take certain actions to ensure that its Transmission Operator Area
operates reliably.
The TOP's authority is established in TOP-001-1a as follows:
R1. Each Transmission Operator shall have the responsibility and clear decision-making authority to
take whatever actions are needed to ensure the reliability of its area and shall exercise specific
authority to alleviate operating emergencies.
R3. Each Transmission Operator, Balancing Authority, and Generator Operator shall comply with
reliability directives issued by the Reliability Coordinator, and each Balancing Authority and
Generator Operator shall comply with reliability directives issued by the Transmission Operator,
unless such actions would violate safety, equipment, regulatory or statutory requirements. Under
these circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform
the directive so that the Reliability Coordinator or Transmission Operator can implement alternate
remedial actions.
The 2012 GMD Report contains web links for some TOP Operating Procedures to mitigate the effects of
GMD events. Recently the GMD Task Force developed Operating Procedure templates that provide a
technical resource for TOPs to use in developing procedures based on industry best practices. Included in
the templates are actions that could be employed to mitigate the effects of GMD, such as reduction of
equipment loading, increasing reactive reserves, reconfiguration of the system, recalling outages, and Load
shedding. The templates also describe indicators of GMD conditions that could be used as trigger
conditions for steps or tasks in an entity's Operating Procedures. Detailed study of system and equipment
impacts can improve Operating Procedures. However some procedures can be put in place by all TOPs to
increase situational awareness and posture the system when a GMD event is forecasted.
Justification for Omitting Functional Entities
Balancing Authority
BAs are responsible for the Real-time balancing of the system. In order to carry out that responsibility,
BAs will dispatch generation, use regulation and other ancillary services, to keep Area Control Error (ACE)
within reasonable limits while maintaining system frequency. BAs will work with the TOP to adjust voltage
schedules or redispatch generation at the request of the TOP to ensure that the transmission system is
operated within thermal, voltage, and stability limits.
The BA can be expected to address GMD impacts through use of generation. However, the BA would not
initiate actions unilaterally during a GMD event and would instead respond to the direction of the TOP
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
and RC. As such, the independent actions that the BA would take are very limited, if any. For example, if
redispatch of generation or adjustment of voltage schedules were needed, the BA would not take those
actions without a request and the concurrence of the TOP and/or RC.
The RC and TOP will be preparing GMD Operating Plans, Operating Processes, and/or Operating
Procedures to address steps that each will be taken to address GMD impacts. Some of those steps will
require the BA to take action. As outlined above, the requirement for the BA to execute actions at the
request of the TOP or RC is clear. Given that the BA would only take action at the request of the TOP or
RC and that the required actions would be the same actions BAs take for other sytem events, the SDT
concludes that the BA should not be included as an applicable entity in EOP-010-1.
Generator Operator
GOPs are the functional entity that operate generating unit(s) and perform the functions of supplying
energy and reliability related services. They may be responsible for operating generator step up (GSU)
transformers that connect the generator to the transmission system. Some GSU transformers are
susceptible to geomagnetically-induced currents (GICs) during a GMD event, and operating actions are
used by some GOPs to mitigate system or equipment impacts.
An effective GOP GMD Operating Procedure to mitigate the effects of GMD would require:
1. GSU transformer study to determine expected GIC on the GSU high side neutral level at their site
(GIC/thermal rating study)
2. Ability to monitor GIC at the GSU high voltage wye-grounded winding neutral
Absent the above information, the GOP would not have the technical basis for taking steps on its own and
would instead take steps based on the RC or TOP’s Operating Plans, Processes, or Procedures. Therefore,
the SDT concludes that GOPs should be excluded as applicable entities in EOP-010-1.
Some GOPs already have GMD Operating Procedures for their equipment based on prior studies and/or
monitoring equipment. EOP-010-1 will not prohibit or interfere with a GOP's established procedure.
Furthermore, the RC and TOP will be preparing GMD Operating Plans and Operating Processes or
Procedures, respectively. Those will address steps that each will be taking to address GMD impacts,
which may include requiring one or more GOPs to take action. Existing standards provide obligations for
the GOP to execute actions when requested by the TOP or RC as described above.
Generator Owners (GOs) and GOPs are included in the Project 2013-03 Standards Authorization Request.
They will be considered for inclusion in Stage 2 standards, which will require applicable entities to conduct
vulnerability assessments and develop appropriate mitigation strategies. Such mitigation strategies could
include the development of Operating Procedures for applicable GOs and GOPs.
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Geomagnetic Disturbance
Operating Procedure Template
Transmission Operator
Overview
Operating procedures are the quickest way to put in place actions that can mitigate the adverse effects of
geomagnetically induced currents (GIC) on system reliability. They also have the merit of being relatively
easy to change as new information and understanding concerning this threat becomes available.
Operating procedures need to be easily understood by, and provide clear direction to, operating
personnel. This is especially true since most operators are unlikely to frequently respond to significant
GMD events.
Some actions listed below should only be undertaken if supported by an adequate GIC impact study
and/or if adequate monitoring systems are available. Otherwise they can make matters worse. Those
actions are indicated by the phrase "if supported by studies".
Determining that a geomagnetic disturbance (GMD) is significant enough to warrant the initiation of
special operating procedure(s) depends on the geographical location of the power system/equipment in
question coincident with the location of the GMD measurement and forecast. Amount of advance notice
obviously factor heavily in what specific actions can and should be taken. Note these are recommended
actions; specific actions may vary by system configuration, system design and geographic location of the
entity.
Information and Indications
The following are triggers that could be used to initiate operator action:
• External:
o NOAA Space Weather Prediction Center or other organization issues:
Geomagnetic storm Watch (1-3 day lead time)
Geomagnetic storm Warning (as early as 15-60 minutes before a storm, and
updated as solar storm characteristics change)
Geomagnetic storm Alert (current geomagnetic conditions updated as k-index
thresholds are crossed )
• Internal:
o System-wide:
Reactive power reserves
System voltage/MVAR swings/current harmonics
o Equipment-level:
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
GIC measuring devices
Abnormal temperature rise (hot-spot) and/or sudden significant gassing (where online DGA available) in transformers
System or equipment relay action (e.g., capacitor bank tripping)
Actions Available to the Operator
The following are possible actions for Transmission Operators based on available lead-time:
Long lead-time (1-3 days in advance, storm possible)
1. Increase situational awareness
a. Assess readiness of black start generators and cranking paths
b. Notify field personnel as necessary of the potential need to report to individual substations
for on-site monitoring (if not available via SCADA/EMS)
2. Safe system posturing (only if supported by study; allows equipment such as transformers and
SVCs to tolerate increase reactive/harmonic loading; reduces transformer operating temperature,
allowing additional temperature rise from core saturation; prepares for contingency of possible
loss of transmission capacity)
a. Return outaged equipment to service (especially series capacitors where installed)
b. Delay planned outages
c. Remove shunt reactors
d. Modify protective relay settings based on predetermined harmonic data corresponding to
different levels of GIC (provided by transformer manufacturer).
Day-of-event (hours in advance, storm imminent):
1. Increase situational awareness
a. Monitor reactive reserve
b. Monitor for unusual voltage, MVAR swings, and/or current harmonics
c. Monitor for abnormal temperature rise/noise/dissolved gas in transformers 1
d. Monitor geomagnetically induced current (GIC 2) on banks so-equipped 3
e. Monitor MVAR loss of all EHV transformers as possible
1
Requires proper instrumentation (e.g., fiber to hot-spot). Note there may be unusual heating in a location other than the normal hot-spot
location. Dissolved gas analysis may be available in real-time if the transformer is so-equipped; otherwise, post-event DGA may be
performed.
2
10 amperes per phase GIC is a good starting point for potential impacts on heavily loaded transformers when actual limits are unknown.
Newer transformers may have significantly higher GIC withstand capability if specified at the time of construction. For vulnerable
transformers, the OEM can perform analytical withstand studies to better define a particular design's GIC vs. Time withstand capability
3
Regarding the effects of GIC on transformers, real-time mitigation (after a storm is already in progress) should not be taken based solely on
a single indicator (e.g., increased GIC). At least one additional indicator should be monitored to determine if the transformer is actually being
adversely affected (e.g., increased MVAR loss, abnormal temperature rise, etc)
Operating Procedure Template for Transmission Operators
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
f. Prepare for unplanned capacitor bank/SVC/HVDC tripping4
g. Prepare for possible false SCADA/EMS indications if telecommunications systems are
disrupted (e.g., over microwave paths)
2. Safe system posturing (only if supported by study)
a. Start off-line generation, synchronous condensers
b. Enter conservative operations with possible reduced transfer limits
c. Ensure series capacitors are in-service (where installed)
Real-time actions (based on results of day-of-event monitoring):
1. Safe system posturing (only if supported by study)
a. Selective load shedding 5
b. Manually start fans/pumps on selected transformers to increase thermal margin (check
that oil temperature is above 50° C as forced oil flow at lower temperatures may cause
static electrification)
2. System reconfiguration (only if supported by study)
a. Remove transformer(s) from service if imminent damage due to overheating (possibly
automatic by relaying)
b. Remove transmission line(s) from service (especially lines most influenced by GMD)
Return to normal operation
This should occur two to four hours after the last observed geomagnetic activity.
Related Documents and Links
2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbance on the Bulk Power
System, dated February 2012
http://www.nerc.com/files/2012GMD.pdf
Industry Advisory: Preparing for Geomagnetic Disturbances, dated May 10, 2011
http://www.nerc.com/fileUploads/File/Events%20Analysis/A-2011-05-10-01_GMD_FINAL.pdf
4
Consideration should be given to replacing protective relaying (as part of planned GIC mitigation projects) to prevent false
tripping of reactive assets due to GIC should be considered. Note that capacitor units have harmonic overload limits that
should be observed (see IEEE Std 18).
5
Giving preference of course to the most critical/sensitive loads (e.g., national security, nuclear fuel storage site, nuclear plant offsite
sources, chemical plants, emergency response centers, hospitals, etc)
Operating Procedure Template for Transmission Operators
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Formal Comment Period: September 4, 2013 – October 18, 2013
Upcoming:
Additional Ballot and Non-Binding Poll: October 9-18, 2013
Now Available
A 45-day formal comment period for EOP-010-1 - Geomagnetic Disturbance Operations
is now open through 8 p.m. Eastern on Friday, October 18, 2013.
As a result of comments received, the drafting team has identified the need to make significant
changes to the standard. Although Section 4.12 of the NERC Standard Processes Manual indicates that
the drafting team is not required to respond in writing to comments from the previous posting when it
has identified the need to make significant changes to the standard, the drafting team is providing
summary responses to the comments received in order to facilitate stakeholder understanding.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, October 18, 2013. Please use
the electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is posted on
the project page.
Next Steps
An additional ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) will be conducted as previously outlined.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Formal Comment Period: September 4, 2013 – October 18, 2013
Upcoming:
Additional Ballot and Non-Binding Poll: October 9-18, 2013
Now Available
A 45-day formal comment period for EOP-010-1 - Geomagnetic Disturbance Operations
is now open through 8 p.m. Eastern on Friday, October 18, 2013.
As a result of comments received, the drafting team has identified the need to make significant
changes to the standard. Although Section 4.12 of the NERC Standard Processes Manual indicates that
the drafting team is not required to respond in writing to comments from the previous posting when it
has identified the need to make significant changes to the standard, the drafting team is providing
summary responses to the comments received in order to facilitate stakeholder understanding.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, October 18, 2013. Please use
the electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is posted on
the project page.
Next Steps
An additional ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) will be conducted as previously outlined.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Additional Ballot and Non-binding Poll Results
Now Available
An additional ballot for EOP-010-1 – Geomagnetic Disturbance Operations and non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern on Monday,
October 21, 2013.
This standard achieved a quorum and sufficient affirmative votes for approval. Voting statistics are
listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Approval
Non-binding Poll Results
Quorum: 77.58%
Quorum: 75.89%
Approval: 88.75%
Supportive Opinions: 90.04%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2013-03 GMD | October 2013
2
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2013-03 GMD Additional Ballot October 2013
Password
Ballot Period: 10/9/2013 - 10/21/2013
Ballot Type: Additional Ballot
Log in
Total # Votes: 308
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 397
Quorum: 77.58 % The Quorum has been reached
Weighted Segment
88.75 %
Vote:
Ballot Results: The Ballot has Closed
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
105
1
71
0.899
8
0.101
0
8
18
10
0.7
7
0.7
0
0
0
1
2
91
1
54
0.915
5
0.085
0
11
21
30
1
15
0.789
4
0.211
0
4
7
89
1
49
0.86
8
0.14
0
9
23
54
1
31
0.838
6
0.162
0
3
14
1
0
0
0
0
0
0
0
1
6
0.4
3
0.3
1
0.1
0
0
2
3
0.2
2
0.2
0
0
0
0
1
8
0.8
8
0.8
0
0
0
0
0
397
7.1
240
6.301
32
0.799
0
36
89
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Segment
1
Organization
Ameren Services
Ballot
Member
Eric Scott
Affirmative
1
American Electric Power
Paul B Johnson
1
American Transmission Company, LLC
Andrew Z Pusztai
1
Arizona Public Service Co.
Robert Smith
1
1
1
1
1
1
1
1
1
1
1
1
John Bussman
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
Abstain
Affirmative
Michael Moltane
Affirmative
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Associated Electric Cooperative, Inc.
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Affirmative
1
Nebraska Public Power District
Cole C Brodine
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
Negative
NERC
Notes
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Foltz (AEP))
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
1
1
1
1
1
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Affirmative
Affirmative
Affirmative
1
Ohio Valley Electric Corp.
Robert Mattey
Negative
1
Oklahoma Gas and Electric Co.
Terri Pyle
Negative
1
1
1
1
1
1
1
1
1
1
1
1
1
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
1
1
1
1
1
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
Bryan Griess
Tracy Sliman
1
1
Tucson Electric Power Co.
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
John Tolo
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Foltz American
Electric
Power)
SUPPORTS
THIRD PARTY
COMMENTS (I support
comments
submitted by
Oklahoma
Gas &
Electric)
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (comments
submitted by
Florida
Municipal
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Power
Agency
(FMPA))
1
1
1
1
1
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
2
BC Hydro
2
2
2
2
2
2
2
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
3
AEP
Michael E Deloach
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Alabama Power Company
Ameren Services
American Public Power Association
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Bartow, Florida
City of Farmington
City of Garland
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Robert S Moore
Mark Peters
Nathan Mitchell
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Dennis M Schmidt
Andrew Gallo
Matt Culverhouse
Linda R Jacobson
Ronnie C Hoeinghaus
Bill Hughes
Bill R Fowler
Roger Powers
Michelle A Corley
Charles Morgan
John Bee
Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
3
Florida Municipal Power Agency
Joe McKinney
3
3
3
3
3
3
3
3
3
3
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Foltz with
American
Electric
Power)
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
Kissimmee Utility Authority
Gregory D Woessner
3
3
3
3
3
3
3
3
3
3
3
3
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
3
Nebraska Public Power District
Tony Eddleman
3
3
3
3
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
Affirmative
Affirmative
Affirmative
Affirmative
3
Oklahoma Gas and Electric Co.
Donald Hargrove
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
4
Blue Ridge Power Agency
Duane S Dahlquist
4
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Reza Ebrahimian
4
Tim Beyrle
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
THIRD PARTY
COMMENTS (FMPA)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted by
Nebraska
Public Power
District by
Don Schmit.)
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Support the
comments of
FMPA)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
4
4
Commission
City of Redding
City Utilities of Springfield, Missouri
Nicholas Zettel
John Allen
Negative
4
4
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
4
4
4
4
4
4
4
4
4
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Jack Alvey
Christopher Plante
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Henry E. LuBean
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Affirmative
Affirmative
Affirmative
4
4
4
4
4
4
4
4
4
5
5
Margaret Powell
Affirmative
Tracy Goble
Daniel Herring
Affirmative
Affirmative
5
Arizona Public Service Co.
5
5
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Steve Wenke
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
5
5
Scott Takinen
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
5
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
5
CPS Energy
Robert Stevens
5
5
5
5
5
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted by
AZPS)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
5
5
5
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions
5
5
5
5
5
5
Dana Showalter
Gustavo Estrada
John R Cashin
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner
Affirmative
Abstain
Florida Municipal Power Agency
David Schumann
Negative
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Affirmative
Abstain
5
Kissimmee Utility Authority
Mike Blough
5
5
5
5
5
5
5
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando
5
5
5
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
5
Nebraska Public Power District
Don Schmit
5
5
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Bernard Johnson
5
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
5
5
5
5
5
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
Mahmood Z. Safi
David Ramkalawan
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
5
PowerSouth Energy Cooperative
Tim Hattaway
5
5
5
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Annette M Bannon
Tim Kucey
Steven Grega
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (I support
comments
submitted by
Oklahoma
Gas &
Electric)
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Affirmative
Affirmative
Affirmative
Steven Grego
Neil D Hammer
Mike Avesing
Henry L Staples
COMMENT
RECEIVED
Affirmative
Affirmative
Oklahoma Gas and Electric Co.
5
5
5
5
Affirmative
David Gordon
5
5
Affirmative
Abstain
Affirmative
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Review
Group (Threshold
should be >
300 MW)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Erika Doot
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Liam Noailles
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
6
AEP Marketing
Edward P. Cox
6
6
Alabama Electric Coop. Inc.
Ameren Energy Marketing Co.
Ron Graham
Jennifer Richardson
6
APS
Randy A. Young
6
6
6
6
6
6
6
6
6
6
6
6
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
FirstEnergy Solutions
Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
Negative
6
Florida Municipal Power Pool
Thomas Washburn
Negative
6
6
6
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
6
Lakeland Electric
Paul Shipps
6
6
6
6
6
6
6
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
6
Northern California Power Agency
Steve C Hill
6
6
6
6
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Joseph O'Brien
Alan Johnson
Douglas Collins
Kelly Cumiskey
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz AEP)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA's
comments)
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
Comments)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Frank
Gaffney's
comments)
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
6
6
6
6
6
6
6
6
6
6
6
6
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina
Affirmative
John J. Ciza
Affirmative
6
6
7
8
8
8
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alcoa, Inc.
8
Foundation for Resilient Societies
William R Harris
8
8
Massachusetts Attorney General
Frederick R Plett
Volkmann Consulting, Inc.
Terry Volkmann
Commonwealth of Massachusetts Department
Donald Nelson
of Public Utilities
Michigan Public Service Commission
Donald J Mazuchowski
National Association of Regulatory Utility
Diane J. Barney
Commissioners
Florida Reliability Coordinating Council
Linda Campbell
Midwest Reliability Organization
Russel Mountjoy
New York State Reliability Council
Alan Adamson
Northeast Power Coordinating Council
Guy V. Zito
ReliabilityFirst Corporation
Anthony E Jablonski
SERC Reliability Corporation
Joseph W Spencer
Texas Reliability Entity, Inc.
Donald G Jones
Western Electricity Coordinating Council
Steven L. Rueckert
6
6
6
6
6
6
9
9
9
10
10
10
10
10
10
10
10
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
David Hathaway
David F Lemmons
Thomas Gianneschi
Roger C Zaklukiewicz
Edward C Stein
Debra R Warner
Abstain
Affirmative
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6b38744f-32c0-46d7-84dc-c369621e7a74[10/22/2013 6:28:55 PM]
Affirmative
Affirmative
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Non-Binding Poll
Project 2013-03
Non-binding Poll Results
Ballot Name: Project 2013-03 Non-binding Poll GMD October 2013
Ballot Period: 10/9/2013 - 10/21/2013
Total # Votes: 277
Total Ballot Pool: 365
75.89% of those who registered to participate provided an opinion or an
Ballot Results: abstention; 90.04% of those who provided an opinion indicated support
for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
Member
1
1
Ameren Services
American Electric Power
Eric Scott
Paul B Johnson
1
Arizona Public Service Co.
Robert Smith
1
1
1
1
1
1
1
1
Associated Electric Cooperative, Inc.
Austin Energy
Avista Utilities
Balancing Authority of Northern California
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
John Bussman
James Armke
Heather Rosentrater
Kevin Smith
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
1
1
Central Electric Power Cooperative
Michael B Bax
Central Maine Power Company
Joseph Turano Jr.
City of Tacoma, Department of Public Utilities,
Chang G Choi
Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston
Clark Public Utilities
Jack Stamper
Colorado Springs Utilities
Paul Morland
Consolidated Edison Co. of New York
Christopher L de Graffenried
CPS Energy
Richard Castrejana
Dairyland Power Coop.
Robert W. Roddy
Dayton Power & Light Co.
Hertzel Shamash
Duke Energy Carolina
Douglas E. Hils
El Paso Electric Company
Dennis Malone
1
1
1
1
1
1
1
1
1
1
Ballot
NERC
Notes
Abstain
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Bob Solomon
Ajay Garg
Martin Boisvert
Molly Devine
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Affirmative
Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Platte River Power Authority
John C. Collins
Portland General Electric Co.
John T Walker
PPL Electric Utilities Corp.
Brenda L Truhe
Public Service Company of New Mexico
Laurie Williams
Public Service Electric and Gas Co.
Kenneth D. Brown
Public Utility District No. 1 of Okanogan County Dale Dunckel
Puget Sound Energy, Inc.
Denise M Lietz
Rochester Gas and Electric Corp.
John C. Allen
Sacramento Municipal Utility District
Tim Kelley
Salt River Project
Robert Kondziolka
San Diego Gas & Electric
Will Speer
SaskPower
Wayne Guttormson
Sho-Me Power Electric Cooperative
Denise Stevens
Snohomish County PUD No. 1
Long T Duong
South Carolina Electric & Gas Co.
Tom Hanzlik
South Carolina Public Service Authority
Shawn T Abrams
Southern California Edison Company
Steven Mavis
Southern Company Services, Inc.
Robert A. Schaffeld
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
1
1
1
1
1
1
1
1
1
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
2
BC Hydro
2
2
2
2
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
Beth Young
Howell D Scott
Steven Powell
Bryan Griess
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Marie Knox
Alden Briggs
Gregory Campoli
Non-binding Poll Results
Project 2013-03 GMD | October 2013
SUPPORTS
THIRD
PARTY
COMMENTS (ACES)
SUPPORTS
THIRD
PARTY
COMMENTS (ACES Power
Marketing)
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
2
2
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
stephanie monzon
Charles H. Yeung
3
AEP
Michael E Deloach
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Alabama Power Company
Ameren Services
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Farmington
City of Garland
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Robert S Moore
Mark Peters
Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Linda R Jacobson
Ronnie C Hoeinghaus
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
Peter T Yost
Gerald G Farringer
Jose Escamilla
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
3
Florida Municipal Power Agency
Joe McKinney
3
3
3
3
3
3
3
3
3
3
3
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (Thomas
Foltz from
American
Electric
Power)
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
Donald Hargrove
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
5
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
4
Blue Ridge Power Agency
Duane S Dahlquist
4
Reza Ebrahimian
4
4
4
4
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy Company
Detroit Edison Company
Nicholas Zettel
John Allen
Tracy Goble
Daniel Herring
Abstain
Affirmative
Affirmative
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
4
4
4
4
4
4
4
4
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Jack Alvey
Christopher Plante
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
John D Martinsen
Affirmative
4
4
4
4
4
4
4
4
5
5
Affirmative
Tim Beyrle
Mike Ramirez
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
5
Arizona Public Service Co.
Scott Takinen
5
5
5
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Matthew Pacobit
Steve Wenke
Clement Ma
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (Support
comments of
FMPA)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (Comments
submitted by
AZPS)
Affirmative
Affirmative
6
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Mike D Kukla
Affirmative
Francis J. Halpin
Affirmative
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
5
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
5
CPS Energy
Robert Stevens
5
5
5
5
5
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
5
5
5
5
5
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Electric Power Supply Association
Essential Power, LLC
First Wind
FirstEnergy Solutions
Gustavo Estrada
John R Cashin
Patrick Brown
John Robertson
Kenneth Dresner
Affirmative
Abstain
5
Florida Municipal Power Agency
David Schumann
Negative
5
5
5
5
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Affirmative
Abstain
5
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Abstain
Dana Showalter
5
Kissimmee Utility Authority
Mike Blough
5
Lakeland Electric
James M Howard
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (ACES)
Affirmative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (Florida
Municipal
Power
Agency)
7
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Western Farmers Electric Coop.
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Daniel Duff
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Tim Kucey
Steven Grega
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Erika Doot
Clem Cassmeyer
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
8
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
6
6
6
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Alabama Electric Coop. Inc.
Ameren Energy Marketing Co.
Linda Horn
Scott E Johnson
Liam Noailles
Edward P. Cox
Ron Graham
Jennifer Richardson
6
APS
Randy A. Young
6
6
6
6
6
6
6
6
6
6
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Duke Energy
El Paso Electric Company
FirstEnergy Solutions
Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
Greg Cecil
Luis Rodriguez
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
Negative
6
Florida Municipal Power Pool
Thomas Washburn
Negative
6
6
6
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
6
Lakeland Electric
Paul Shipps
6
6
6
6
6
6
6
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
6
Northern California Power Agency
Non-binding Poll Results
Project 2013-03 GMD | October 2013
Steve C Hill
Abstain
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS (FMPA's
Comments)
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (FMPA
Comments)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS (Frank
Gaffney's
comments)
9
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Alcoa, Inc.
Joseph O'Brien
Alan Johnson
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Peter H Kinney
Thomas Gianneschi
Roger C Zaklukiewicz
Edward C Stein
Debra R Warner
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
8
Foundation for Resilient Societies
William R Harris
Negative
8
8
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Frederick R Plett
Terry Volkmann
Affirmative
Donald Nelson
Affirmative
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
9
10
10
10
10
10
10
10
10
Non-binding Poll Results
Project 2013-03 GMD | October 2013
COMMENT
RECEIVED
10
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual or group. (37 Responses)
Name (20 Responses)
Organization (20 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS
WITHOUT ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (5
Responses)
Comments (37 Responses)
Question 1 (27 Responses)
Question 1 Comments (32 Responses)
Question 2 (23 Responses)
Question 2 Comments (32 Responses)
Question 3 (25 Responses)
Question 3 Comments (32 Responses)
Question 4 (22 Responses)
Question 4 Comments (32 Responses)
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
According to the ORNL 319 report
(http://web.ornl.gov/sci/ees/etsd/pes/pubs/ferc_Meta-R-319.pdf, Figure 1-17), 3
phase / 3 leg core design transformers are much less likely to saturate and result
in MVAR demands about 25% of that of three single phase transformers. Hence,
the applicability for > 200 kV and < 400 kV (i.e., the 230 and 345 kV transformers)
ought to be limited to single phase transformers connected in a grounded wye
configuration. This is the primary reason for FMPA's negative vote. FMPA also
believes that the 200 kV threshold ought to be raised to 300 kV. The resistance of
230 kV lines is significantly higher than 345 kV lines, which will significantly reduce
GIC (see Figure 1-12 noting that the chart is semi-logarithmic) for lines of similar
length (see figure 1-14). This is largely due to the fact that most 345 kV lines are
two conductor bundles for RFI purposes and most 230 kV lines are single
conductor; hence, 230 kV lines are roughly twice the resistance of 345 kV lines for
the same length of line. Although FMPA believes the threshold should be raised to
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
300 kV, we can "live" with a 200 kV threshold if the applicability to 200 kV is to
TOPs that operate three single leg core design transformers connected in a
grounded wye configuration.
Individual
Nazra Gladu
Manitoba Hydro
Yes
Yes
Yes
No
Group
Arizona Public Service Co.
Janet Smith
Yes
Yes
No
The implementation period should be no less than 1 year, 6 months
implementation time would cause significant strain and will not allow an effective
procedure to be developed.
Yes
Suggest changing R3.2 to as follows: System Operator actions to be initiated based
on predetermined conditions, if known to be a susceptible to GMD. During the
Webinar, it was pointed out that TOP is not required to have a study or
measurement to find the predetermined conditions and most TOP would not
know of such conditions existing in their system. The suggested language change
would make it clear that they are not required to know the predetermined
conditions.
Group
Northeast Power Coordinating Council
Guy Zito
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Yes
The Time Horizon brackets for Requirement R1 incorporate four (4) Time Horizons
shown as: [Time Horizon: Long-term Planning, Operations Planning, Same-day
Operations, Real-time Operations] It is not clear which Time Horizon goes with
what part of Requirement R1. Suggest adding the clarification in a Rationale Box
as follows: Development of the GMD Operating Plan is in the Long-Term Planning
Time Horizon. Maintenance of the GMD Operating Plan is in the Operations
Planning Time Horizon. Implementation of the GMD Operating Plan is in the
Same-Day and Real-Time Time Horizons.
Yes
Yes
Yes
The text of the "Effective Dates" section should be consistent with the EOP family
of standards to reduce the variance between EOP Standards. Regarding
Requirement R1 and its Measure M1, times for completion need to be added. The
Violation Severity Levels have to be revised accordingly. The contents of the
Rationale Boxes for R1 and R3 as they shown are obvious, and can be removed. In
the response to Question 1 above we suggested an addition to the Rationale Box
for R1. The Rationale Box for R2 should not repeat wording from R2.
Group
PacifiCorp
Ryan Millard
Yes
Yes
Yes
Yes
Individual
Ayesha Sabouba
Hydro One
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
A process for the RC to review the GMD Operating Procedures of TOs in the RCA
from the point of view of coordination is needed.
Yes
Yes
No
Individual
Thomas Foltz
American Electric Power
No
While AEP welcomes the removal of the word “coordinate” as an action
performed by the RC, the word is now used as something that is done by the
Operating Plan. Despite this change, and because the RC is required to implement
the Operating Plan, there still appears to be an “implied” obligation where the RC
must coordinate. This term remains vague, and more specific text should be used
in its place such as “affirm the compatibility of Operating Procedures and
Operating Processes among the entities within the Reliability Coordinator Area.”
Operating Plans developed by Reliability Coordinators may be quite different from
area to area, which may be necessary in some circumstances. However, because
AEP serves in multiple Operating Regions, we hope that the various Operating
Plans, when feasible, are uniform for the most part. R1 states that the Operating
Plan must coordinate GMD Operating Procedures, but makes no mention of the
Operating Process as required in R3. Similarly, R1.2 requires a process to review
GMD Operating Procedures but again makes no mention of reviewing Operating
Processes. We recommend adding “Operating Processes” in R1 and R1.2, so that
R1 reads “Each Reliability Coordinator shall develop, maintain, and implement a
GMD Operating Plan that coordinates GMD Operating Procedures or Operating
Processes within its Reliability Coordinator Area.” and that R1.2 reads “A process
for the Reliability Coordinator to review the GMD Operating Procedures or
Operating Processes of Transmission Operators in the Reliability Coordinator
Area.”
No
We do not believe failure to meet R3.3, i.e. failure to terminate the Operating
Procedure or Process after a GMD event, justifies a Medium VRF. Instead, a “Low”
VRF is recommended.
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
The time horizon “Long-term Planning” seems more appropriate for the Stage 2
aspect of this GMD standard, and not for the Stage 1. Please provide carification
for how Long-term Planning is to be applied for R1 and R3 as well as justification
for doing so. Although this may be ouside the scope of this project team, we
encourage NERC to resolve the discrepancies between the definition of Long-term
Planning as provided in NERC’s Time Horizon and the definition of “Long-Term
Transmission Planning Horizon” in the NERC Glossary of Terms. AEP recognizes the
perceived urgency of this project, supports the objective of the proposed
standard, and appreciates the efforts of the drafting team. Our negative vote is
driven solely by our desire for additional clarity as stated in our comments. AEP
foresees voting in the affirmative once the issues and concerns expressed in this
response are addressed in future versions of the draft.
Individual
Anthony Jablonski
ReliabilityFirst
Yes
ReliabilityFirst votes in the affirmative because this standard will help to mitigate
the effects of geomagnetic disturbance (GMD) events by requiring the Reliability
Coordinator to implement Operating Procedures and the Balancing Authorities
and Transmission Operators to implement Operating Plans. ReliabilityFirst offers
the following comments for consideration: 1. Requirement R1 - To be consistent
with the language in Requirement R3, ReliabilityFirst believes the term “Operating
Process” should be added to Requirement R1. Furthermore, Requirement R1
should include a statement tying it back to the Transmission Operator’s Operating
Procedure or Operating Process in Requirement R3. ReliabilityFirst recommends
the following for consideration: “Each Reliability Coordinator shall develop,
maintain, and implement a GMD Operating Plan that coordinates GMD Operating
Procedures [and Operating Processes, as developed in Requirement R3,] within its
Reliability Coordinator Area. At a minimum, the GMD Operating Plan shall
include:…” 2. Consideration for new Requirement R4 - ReliabilityFirst submitted
this comment during the last comment period but believes it may have been
overlooked (i.e., we believe it was not addressed in the consideration of
comments report). ReliabilityFirst recommends including a new Requirement R4
which would require adjacent Reliability Coordinators to share their respected
GMD Operating Plans. During a GMD event, it can span multiple Reliability
Coordinator areas and ReliabilityFirst believes the adjacent Reliability
Coordinators should be aware of each other’s GMD Operating Plans.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
Yes
Yes
Because GMD can be a wide area event the TOP efforts should focus on
coordinating operations and procedures with the RC. Also, GMD is a high-impact,
low-frequency event so overall risk to the TOP should be assessed to make certain
the operations and procedures are commensurate with the risk to reliable
operation of the Bulk Electric System.
Yes
Public Utility District No.1 of Snohomish County agrees in general, however
appropriate implementation time should be given so that the Reliability
Coordinator (“RC”) has the time to develop the GMD operating plan and
coordinate with neighboring RCs as well as other impacted functions.
Although GMD and Geomagnetically Induced Currents (“GIC”) have been well
understood for many decades, how they impact various elements of the power
grid are still being assessed by the electric industry and equipment manufacturers.
Significant discussion has taken place on this subject in many different forums;
however there is very little credible analysis on the level of impact a GMD can
have on the BES and what level of risk a GMD poses compared to other adverse
impact events.
Individual
John Seelke
Public Service Enterprise Group
No
R2 states “Each Reliability Coordinator shall disseminate forecasted and current
space weather information as specified in the Reliability Coordinator's GMD
Operating Plan.” We agree, but in R1 which requires such a plan, there is not
requirement related to R2. We believe R1 should have subpart 1.1 rewritten as
follows: 1.1 A description of activities designed to mitigate the effects of GMD
events on the reliable operation of the interconnected transmission system within
the Reliability Coordinator Area WHICH INCLUDE AN ACTIVITY TO DISSEMINATE
FORECASTED AND CURRENT SPACE WEATHER INFORMATION.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
No
I believe that either this standard should only apply to the RC or the stage 1
directives should be addressed outside the standards process. Recent GDM events
have shown little to no impact on the Bulk Electric System and creating a GDM
Operating Plan requirement and auditing process is likely to have little reliability
impact other than blindly following the letter of these directives.
No
No
No
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
Seminole asks the SDT to add language to the Standard that indicates that
Industry and NERC intend to allow for consideration of system topology, including
geographical orientation, in developing a GMD Operating Plan. Seminole is aware
that this is the intent of the SDT and therefore Seminole proposes the following
language, or similar language, be added in each Requirement requiring an Entity
to develop a type of GMD Operating Plan and/or set of Operating Procedures: “An
Entity can take into consideration such entity-specific factors such as geography,
geology, and system topology in developing a GMD Operating Plan/set of
Operating Procedures.” Seminole acknowledges that the SDT did not adopt this
suggestion during the last comment period for the reason that the SDT did not
wish to begin naming criteria that could be utilized in documenting an Operating
Plan, i.e., an exhaustive list. However, while reviewing the SDT’s Network
Applicability document posted with this Standard, NERC incorporated two out of
the three Network Definition Considerations into the Proposed Standard, those
two being the wye-grounded power transformer requirement and the lower limit
voltage of 200 kV, while not adopting the system topology consideration.
Seminole agrees with NERC that this is an important consideration in assessing
GMD impacts and believes that this should be incorporated into the Standard in a
manner that does not restrict additional considerations. As previously noted, the
above suggested language comes directly from the SAR for this project.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Group
NERC Compliance Policy
Connie Lowe
Yes
Yes
Individual
Phil Anderson
Idaho Power
Yes
Yes
Yes
No
Group
Colorado Springs Utilities
Kaleb Brimhall
NA
Yes
• Thank you for your efforts. The standard drafting team has not provided
sufficient technical justification for the 200 kV threshold. Utility research indicates
that the threshold should begin more around the 300kV threshold.
Yes
Yes
Yes
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1. Thank you for all of your work SDT! 2. For the record. We have concern over the
fact that action is being required prior to defining the risk? A blind shotgun
approach consumes a lot of unnecessary resources, as it is anticipated that there
are many entities that will not be at risk to GMDs. We understand that FERC is
pushing for action, but think that their push should be founded on established
risk.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC Operating Committee (OC)
Individual
Michael Falvo
Independent Electricity System Operator
Yes
(1) We agree with all the proposed changes, and commend the SDT for
responding positively to industry comments especially those that propose
removal of the P.81 type of requirements, and the apparent redundancy/overlap
with IRO-005-3.1a, R3. However, we believe Part 1.2 should be expanded to
convey the need for developing recourse. Part 1.2 stipulates that the RC’s GMD
Operating Plan shall include: 1.2. A process for the Reliability Coordinator to
review the GMD Operating Procedures of Transmission Operators in the Reliability
Coordinator Area. When a RC’s review of the TO’s operating procedures finds
something lacking, then the recourse to make corrections should be made more
clear. We suggest Part 1.2 be revised as follows: 1.2. A process for the Reliability
Coordinator to review the GMD Operating Procedures of Transmission Operators
in the Reliability Coordinator Area, and direct the Transmission Operators to
correct deficiencies, if any. If the SDT accepts this recommendation, please make a
mirror change in R3 that will require the TOP to comply with the RC’s directive for
correcting the deficiencies. (2) R2 as written is unclear on to whom the weather
condition is to be provided. We suggest R2 to be clear that the RC is disseminating
space weather information to TOPs, as stated in the Background Information in
the Comment Form “A new Requirement R2 has been added to the standard,
which would require RCs to disseminate space weather forecast information to
TOPs in the Reliability Coordinator Area (RCA). (3) R3 – The term ‘Operating
Process’ is unnecessary and inconsistent with the wording in R1. We suggest to
remove “or Operating Process” from R3 in the statement “Each Transmission
Operator shall develop, maintain, and implement an Operating Procedure or
Operating Process…”.
Yes
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Yes
Individual
Kathleen Goodman
ISO New England Inc.
Agree
IRC SRC
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Agree
SERC OC Review Group
Individual
Richard
Vine
Agree
The ISO supports the comments submitted by the ISO/RTO Standards Review
Committee
Individual
Alice Ireland
Xcel Energy
Yes
We have the following additional comments, but don’t view them as show
stoppers. Because R2 specifies that the RC must disseminate space weather
information as specified it he RC GMD Op Plan, it would seem logical that there be
a sub requirement in R1 that requires the RC has a process to distribute the space
weather and list the entities and/or functions for distribution. R3.1 seems
unnecessary since R2 requires the RC to disseminate space weather info,
presumably the TOPs are included. It isn’t clear what steps or tasks an entity
would have to ‘receive’ space weather information.
Yes
none
Individual
Don Schmit
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Nebraska Public Power District
Yes
NPPD supports the comments submitted by the Southwest Power Pool. In
addition we would like to add this comment: “The drafting team is requiring
operating procedures to be in place prior to studying the GMD effects on the TOP
system. To determine what effects the GMD will have on the TOP’s system, the
studies should be preform first and then the operating procedures developed. The
drafting team is requiring generic operating procedures which may or may not
address the GMD issues on the TOP’s system. It makes more sense to delay the
implementation of the operating procedures until the studies have been
performed.”
Group
SERC OC Review Group
Sammy Roberts
Yes
In R1 the requirement calls for the RC to review an “Operating Procedure”. We
request the SDT to consider adding “Operating Process” so it is consistent with R3.
Yes
Yes
We would like to thank the SDT for their responses to stakeholder comments. The
comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Review Group only and should not be construed
as the position of the SERC Reliability Corporation, or its board or its officers.
Group
SPP Standards Review Group
Robert Rhodes
No
We propose changing the wording in Section 4.1.2 under Applicability to read:
Transmission Operator with a Transmission Operator Area that includes a power
transformer with a high-side, wye-grounded winding with a terminal voltage
greater than 200 kV. This clarifies that the 200 kV winding is the high-side, wye-
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
grounded winding. We suggest changing the ‘the Reliability Coordinator Area’ to
‘its Reliability Coordinator Area’ in R1.2. We suggest replacing ‘respective system’
with ‘Transmission Operator Area’ in R3. This language would then parallel that of
R1.
Yes
We would prefer to see the VRFs at Low rather than the assigned Medium, but
can live with them as proposed.
Yes
The treatment of the Effective Date in the standard appears to address the issue
of implementation in the Canadian provinces. Hopefully this will resolve the issue.
Yes
We want to thank the drafting team for taking the time to provide summary
responses to help the industry’s understanding of the changes even though they
didn’t have to.
Group
Duke Energy
Colby Bellville
Yes
In R1.2, the requirement calls for the RC to review an “Operating Procedure”.
Duke Energy recommends adding “Operating Procedure or Operating Process”for
consistency with R3.
Yes
Yes
Yes
Duke Energy would like to thank the SDT for their response to stakeholder
comments.
Group
ISO/RTO Council Standards Review Committee
Greg Campoli
Yes
We agree with most of the proposed changes, and commend the SDT for
responding positively to industry comments especially those that propose
removal of the P.81 type of requirements, and the apparent redundancy/overlap
with IRO-005-3.1a, R3. Nevertheless, we offer the following comments intended
to further improve the standard. 1. Certain wording in the proposed R2 introduces
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
an unclear requirement in R2 and implied requirements in R1. R2 stipulates that
the RC shall dissemintate forecasted and current space weather information “as
specified in the Reliability Coordinator's GMD Operating Plan”. It is not clear what
is it in the GMD Operating Plan that the RC must follow: is it the entities to whom
the RC need to disseminate the information, or is it the forecast and current space
weather information, or is it the timing for the dissemination, or a combination or
all of the above? R1 does not provide this detail. We suggest the SDT to either add
the detail in R1, or to remove or reword the phrase “as specified in the Reliability
Coordinator’s GMD Operating Plan” to remove the uncertainty and implied
requirement. 2. We would also suggest some wording change to R1, which
currently stipulates that: R1. Each Reliability Coordinator shall develop, maintain,
and implement a GMD Operating Plan that coordinates GMD Operating
Procedures within its Reliability Coordinator Area. A plan does not ”coordinate”.
Depending on the intent of the requirement – whether it mandates the RC to
coordinate the GMD operating procedure or the RC to have a GMD operating plan
that contains the coordinated operating procedures, and to more specifically
indicate who to coordinate with, a more appropriate wording could be: “Each
Reliability Coordinator shall develop, maintain, and implement a GMD Operating
Plan to coordinate GMD Operating Procedures of the Transmission Operators
within its Reliability Coordinator Area.” Or, the wording could be: “Each Reliability
Coordinator shall develop, maintain, and implement a GMD Operating Plan that
reflects (or covers or stipulates) the coordinated GMD Operating Procedures of
the Transmission Operators within its Reliability Coordinator Area.”
Yes
Yes
No
Group
Oklahoma Gas & Electric
Don Hargrove
Yes
The Standard, as written, requires entities to have a plan, but it fails to identify a
clear and measurable expected outcome, such as a stated level of reliability
performance, a reduction in a specified reliability risk (prevention), or a necessary
competency.
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Group
Southern Company
Wayne Johnson
Agree
SERC OC
Group
US Bureau of Reclamation
Erika Doot
Yes
The Bureau of Reclamation (Reclamation) appreciates the drafting team’s decision
to require Reliability Coordinators (RCs) to disseminate space weather information
rather than requiring each TOP to acquire and disseminate space information.
Yes
Yes
Reclamation appreciates the drafting team’s efforts to avoid a situation where
both IRO-005-3.1a Requirement R3 and EOP-010 Requirement R2 are effective at
the same time.
Group
ACES Standards Collaborators
Ben Engelby
Yes
1) The draft standard is much improved over the previous version. We thank the
drafting team for removing the administrative requirements and removing BA
applicability. We also agree that the standard does address the FERC directive.
However, we believe there is another option that is as equally effective, is actually
more efficient than writing a new standard and eliminates the redundancy that
this proposed standard creates. The other option is to rely on existing standards.
TOP-001-1a R2 and R8 already require the TOP to take immediate actions to
alleviate operating emergencies and to restore reactive power balance. TOP-0022.1b R8 requires the TOP to plan to meet voltage and/or reactive limits, including
the deliverability/capability for any single Contingency. TOP-004-2 R6.1 requires
the TOP to have policies and procedures for monitoring and controlling voltage
levels and reactive power flows. EOP-001-2 R2.2 requires the TOP to “develop,
maintain, and implement a set of plans to mitigate operating emergencies on the
transmission system.” IRO-014-1 R1 requires the RC to have operating procedures,
processes or plans for activities that require notification or exchange of
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
information with other reliability coordinators. Since the electric industry already
takes an “all hazards” approach to planning the operation of the grid, the RCs in
geographies with greater risks to GMD events should be able to rely on existing
processes, procedures and plans to coordinate responses to GMD events. The
electric industry’s excellent response to large events such as hurricanes has
proven the “all hazards” approach to planning is effective. Since these standards
requirements are applicable at all times including during GMD events, the
proposed requirements will create an opportunity for double jeopardy due to the
redundancy in the requirements.
No
Because we question the need for the standard at this juncture, we cannot
support the VSLs or VRFs. At best, the VRFs should all be low. For a requirement to
be assigned a Medium VRF, a single violation of the requirement would have to
“directly affect the electrical state or the capability of the bulk electric systems, or
the ability to effectively monitor and control the bulk electric system” as defined
in the Medium VRF definition. A single violation of any of these requirements will
not “directly affect the electrical state or the capability of the bulk electric
systems, or the ability to effectively monitor and control the bulk electric system.”
Other standards would have to be violated first. For example, both TOP-002-2.1b
R8 and TOP-004-2 R6.1 would have to be violated as well to effect the electrical
state, monitoring and control of the bulk electric system. TOP-002-2.1b R8
requires the TOP to plan to meet voltage and/or reactive limits, including the
deliverability/capability for any single contingency. TOP-004-2 R6.1 requires the
TOP to have policies and procedures for monitoring and controlling voltage levels
and reactive power flows. Other requirements that would have to be violated
include EOP-001-2 R2.2 and IRO-014-1 R1.
Yes
While we continue to believe there is another equally efficient and more efficient
alternative to development of this standard, the implementation plan is
reasonable within the constraints of this standard. However, we have concerns
that the second phase of this project may alter the work done in phase one,
including modifications to the implementation plan and the entities that could be
subject to compliance with this standard.
Yes
(1) Requirement R2 should be made a sub-part of Requirement R1 to avoid double
jeopardy and because it is essentially a constraint on the Operating Plan. If a
registered entity fails to write an Operating Plan, it will also fail to include in its
Operating Plan the method for disseminating space weather. Since violations are
assessed per requirement, one compliance failure could result in two compliance
violations of R2 and R3. Thus, if R2 is written as a sub-part of R1, failure develop
an Operating Plan will be assessed as a single violation of the combined
requirement. Furthermore, R2 essentially is a requirement for what should be
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
contained in the Operating Plan and, therefore, more appropriately belongs as a
sub-part of R1. (2) Part 3.1 in R3 is unnecessary and redundant with other
requirements. R2 already compels the RC to disseminate space weather
information. Because the RC is a higher authority than the TOP, the TOP is already
required to receive the information as a result by implication. The RC’s authority is
documented in IRO-001-1a R3 and R8. The RC may issue directives to the TOP to
follow its GMD Operating Procedure or Process while disseminating information
about severe space weather. Furthermore, NERC already designates MISO and
WECC RC to monitor the space weather through the National Oceanic and
Atmospheric Administration (NOAA) Space Weather Prediction Center (SWPC).
MISO communicates this information to the Eastern and ERCOT Interconnections
through reliability coordinator information system (RCIS) and WECC
communicates it to the Western Interconnection as documented in a NERC alert.
Codifying a process that is already in place and works effectively only perpetuates
the existing compliance model that places too much emphasis on documentation
and not enough on reliability. (3) The SAR should be modified to indicate that
Stage 1 will require registered entities to develop and implement Operating
Processes and Operating Plans in addition to Operating Procedures. The SAR only
references the development and implementation of Operating Procedures which
is not consistent with the standard that includes Operating Plans and Operating
Processes. (4) We believe the literal meaning of the language in R3 Part 3.3 is not
what is intended by the drafting team. As written, the language could be read to
literally mean that the Operating Process or Operating Procedure must include
language for retiring the Operating Process or Procedure. The problem is with the
use of “terminate the Operating Procedure or Operating Process.” Terminate
means to come to an end. Thus, terminating the Operating Procedure or
Operating Process which are documents means to end the document. Obviously,
the purpose is to terminate the use of the Operating Procedure or Operating
Process when the GMD event has ended. We suggest using the language from the
SAR for R3 Part 3.3 as it is clearer and has a more exact meaning of what is
intended. The language in the SAR is: “Criteria for discontinuing the use of
Operating Procedures at the conclusion of a GMD event.” (5) The Long-term
Planning Time Horizon for R1 and R3 should be removed. The functional entities
to which the standard applies are not planning entities per the functional model
and have no long-term planning responsibilities. The Long-Term Planning Horizon
covers a period of one year or longer. An operating procedure or plan will cover
the Real-Time Operations horizon or Operations Planning horizon at best. By NERC
Glossary definition, an operating plan, process or procedure will not cover the
Long-Term Planning horizon. An operating procedure lists the specific steps that
should be taken by specific operating positions. An operating process includes
steps that may be selected based on “Real-time conditions.” An operating plan
contains operating procedures and processes which are applied in real-time
operations. (6) We are concerned that implementation of an operating procedure
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
for GMD may require the removal a number of transformers and could be viewed
as causing a burden to neighboring systems contrary to TOP-001-1a R7. TOP-0011a R7 compels the TOP and GOP to not remove facilities from service if it would
burden neighboring systems unless there is not time for notification and
coordination. Could the requirement to write an operating procedure for
responding to GMD events be viewed as allowing time for coordination and
notification particularly if the TOP documented in their plan to notify their RC? If
EOP-010 persists, TOP R7.3 should be modified to clarify that a TOP and GOP may
not have sufficient time during an extreme GMD event to make appropriate
notifications and the requirement for the RC to have an operating plan will satisfy
this required coordination. (7) The white paper supporting functional entity
applicability should be modified. On page three, the last sentence just before the
“Justification for Omitting Functional Entities” section is inconsistent with the
standard. It states that “some procedures can be put in place by all TOPs.” The
standard limits the procedures to only TOPs with a transformer with a high-side
wye-grounded winding greater than 200 kV. Please modify the sentence in the
whitepaper for consistency with the standard. (8) We do not believe the science
of how GMDs impact the electric grid is settled. This is evidenced by multiple
reports with significantly varying conclusions. While the FERC order indicated that
most reports agree that there is a minimum risk for voltage collapse due to
excessive reactive power consumption of transformers during extreme GMD
events, the reports may not emphasize the geographic risk of the problem. For
example, does a utility in South Florida have the same risk as a utility in northern
Maine? If the risks are different, a requirement for an operating procedure for all
entities including the southernmost entities is premature at this point. We
understand that NERC has an obligation to respond to the FERC GMD directive
and will support them in their efforts, however, we wonder if NERC should look
for an equally efficient and effective alternative. We believe that such an
alternative should include pointing to the existing and proposed standards
requirements that require registered entities to respond to voltage emergencies
as documented in our responses to other questions. (9) Thank you for the
opportunity to comment.
Individual
Cheryl Moseley
Electric Reliability of Texas, Inc.
Yes
ERCOT generally supports the SDT's efforts in developing the draft GMD standard
and believes it is on the right track. However, the SDT should consider the
following comments in the development of future versions. Most of the
requirements seem to be concentrating upon the administration of “having
procedures”. The standard should say “what” is required, while minimizing the
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
required administration activities. 1) Applicability Section The SDT should consider
the role of GOPs in the standard. The standard in both its initial and revised form
does not address the GOP function. GOPs may have GMD operating plans in place.
As the whitepaper on applicable functions noted - “Some GOPs already have GMD
Operating Procedures for their equipment based on prior studies and/or
monitoring equipment. EOP-010-1 will not prohibit or interfere with a GOP's
established procedure.” Given that generators may have GMD procedures in
place, the standard should reflect those procedures on a stand alone basis and as
inputs into the larger operational GMD procedures. The failure to consider those
plans in developing and coordinating the broader scope operational plans would
create a disconnect between core operational roles. Such disconnects could
undermine the effective and efficient management of GMD events potentially
creating an undesirable reliability impact on the interconnection. Accordingly, the
SDT should consider revisions to include the GOP function to ensure generator
GMD procedures are considered and reflected in the larger scope GMD
operational procedures. These plans should be coordinated with the relevant TOP
and RC plans in a coordinated manner that is ultimately overseen by the RC, as
proposed in the standard. 2) Requirement 1.2 The revised standard removes the
coordination/compatibility determination role of the RC. It seems the RC should
be performing these roles to ensure effective and efficient operations in the
context of a GMD event. It is not clear that a simple “review” role is adequate to
achieve that outcome. The SDT should reconsider whether the RC should have the
ability/authority to address any potential conflicts in plans pursuant to a
coordination/compatibility determination role. If the revision was intended to
simply be a “clean-up” edit, and that the coordination role is adequately covered
in the R1 coordination role, R1 should reference R 1.2, so it is clear that the plans
referenced in R1 are defined in terms of the specific functional entity referenced
in R1.2. 3) Measure 1 The revisions to M1 includes language that calls for evidence
related to implementation to be that which demonstrates the entity performed
the action "as called for in the GMD Plan...".While ERCOT understands the value
of linking implementation evidence to the plan, the way it is drafted it could be
interpreted very rigidly such that any operational deviation from the plan would
be a violation. Obviously if you have a plan it should be used, but neither the
standard nor the measure should be so rigid that if the operators cannot deviate
from the plan if necessary based upon unintended circumstances without the risk
of noncompliance with this requirement - entities should be able to take actions
outside the four corners of the plan if necessary, and the standard and compliance
measures should clearly accommodate such actions to avoid unintended
consequences where the best operational actions are not taken because entities
do not want to risk noncompliance. 4) Requirement 2 Requirement 2 mandates
that the RC share forecasted and current space weather information in
accordance with its plan. As an initial matter, this implicitly requires RCs to have
forecasted and current space weather information in our plans even though the
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
substantive requirements related to the plan in R1 don't require that. This creates
ambiguity in terms of whether that is a substantive obligation for the plan. For
example, can an RC not have this in their plan, and, if so, does that make that
requirement inapplicable in an audit? Another potential ambiguity related to this
requirement is that there is no direction in terms of the entities the RC is required
to disseminate this information to under the requirement. ERCOT understands the
standard leaves this to the RC plan, but again, does that mean the RC does not
have to have this in its plan? If this obligation is retained, the scope should be
aligned with the functional entities in the standard that have GMD procedural
roles (currently just TOPs – although as noted ERCOT questions whether GOPs
need to be included in the standard). Also, if this is going to be a plan requirement
that should be explicit. To make it clear, it should be established as a substantive
component of the plan as part of R1. However, ERCOT does not support this as a
substantive requirement. The standard should dictate the substance of functional
entity plans. ERCOT also questions the need for the RC to disseminate that
information. The information can be obtained by other functional entities
independent of RC dissemination, and that obligation, if the SDT elects to require
entities to obtain this information, should be assigned to those entities. As
drafted, this unnecessarily creates an opportunity for RC non-compliance with
what is really administrative obligation i.e. distributing information that can be
obtained independent of the RC. To the extent there is an inconsistency risk in
terms of the sources/substance of this information, that risk could be managed by
the RC coordination role. In addition to the above issues, the requirement is
otherwise vague and ambiguous in terms of the scope of the information
disseminated. For example, what is the timing for the dissemination? Again, the
draft language leaves this to the RC plan, but as discussed, it is not clear if the RC
has to have anything related to this, and if it does not, what the impact of that
would be in an audit. If this implicitly requires the RC to have this process in its
plan, the issue is what is the scope for all aspects – e.g. audience, timing, etc.?
Granted the way it is drafted the RC has complete discretion, but there is a
concern whether that discretion will be respected by the ERO in the exercise of its
CMEP function. To mitigate the potential issues with this requirement, ERCOT
believes it should be removed because the standard should require a plan, but
should not dictate the substantive components of the plan. Alternatively the
standard should be revised to make the obligations explicit and clear with respect
to what is required – e.g. R 3.1 makes it clear that TOPs are required to have a
process to obtain space weather information. 5) Requirement 3 Related to the
above comments on R2, R3 requires TOPs to get space weather info. Given this
independent obligation, why does the RC have an obligation to disseminate that
info? As discussed, it is unnecessary and creates unnecessary compliance risk. 6)
Requirements 3.2 and 3.3 As drafted, these requirements seem too prescriptive.
While it is reasonable that a plan establishes actions relative to specific conditions.
However, the language should be clear that these are recommended actions, but
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
are illustrative and non-exclusive. Functional entities should have the flexibility
necessary to take actions outside of the plan if operating conditions change and
counsel for operating actions outside of the four corners of the plan. 7) Measure 3
Similar to the above comment on Measure 1, as drafted, Measure 3 could be
interpreted in a manner that is too prescriptive and limiting, which could create
the risk of undermining effective operations by limiting operator actions to the
four corners of the plan or risk noncompliance risk. This would undermine the
operational flexibility necessary to act outside of the plan if system conditions
warranted such actions without risking violation of the requirement.
Yes
Yes
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
Yes
Yes
BPA recommends the drafting team change the language of the first sentence of
R3, from “Each Transmission Operator shall…or Operating Process to mitigate the
effects of GMD events on the reliable operation of its respective system.” To
“Each Transmission Operator shall…or Operating Process intended to mitigate the
effects of GMD events on the reliable operation of its respective system.”
Individual
Sergio Banuelos
Tri-State Generation and Transmission Association, Inc.
Yes
Yes
Yes
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Yes
Tri-State is still concerned with the Standard Drafting Team’s decision setting the
limit of applicable transformers from >200kV versus >300kV. This critical decision
will have significant cost and time ramifications on the industry. The workload for
Tri-State will increase nearly five-fold based on the amount of transformers that
fall into the 200-300kV range. We appreciate the work that the volunteer task
force has accomplished in helping to prepare the NERC “Network Applicability”
paper, but Tri-State believes such a critical decision in setting the limit should be
based on more extensive knowledge. The “Network Applicability” justification for
including 200kV circuits is only based on an analysis of a small simulated network
consisting of two 500/230kV autotransformers with only a few lines running into
and out of that station. That analysis, summarized in Table A1 (pg. 7), predicts a
decrease of GIC from 5.5 to 2.8 Amps if the 230kV elements are included. The
study also estimates an increase in var absorption from 12.5 to 14 Mvar if the
230kV elements are included. Tri-State suggests that these slight variances are
well within the error range in the overall assumptions for the many parameters
used to predict GIC itself. Parameters such as the line induced kV/km, the
magnitude and duration of solar events, the deep earth soils geology, accuracy of
the transformer models, ground grid resistance (which may vary season to
season), etc. Our suggestion is to give the NERC task force increased time to do
research and in the meantime adopt a criteria of detailed analysis of >300kV with
a 10% safety factor added for the possible <300kV impact.
Group
Foundation for Resilient Societies
William R. Harris
No
Question 1: Our Foundation's Case Study on Maine and ISO New England's
capacity to mitigate a severe solar geomagnetic storm (March 2013 - found on
website www.resilientsocieties.org) reaffirmed our prior understanding that the
Regional Coordinators (in this case ISO-New England) cannot adequately
coordinate "operating procedures" to mitigate a severe GMD event without
concurrent jurisdiction over Balancing Authorities (BAs) and Generator Operators
(GOs). In a severe solar storm, the combination of generation reserves together
with demand response reserves may not enable Regional Coordinators (RCs) to
balance loads without active preparation and support of balancing authorities. For
ISO-New England that would include Canadian resources and balancing operators
beyond the authority and scope of FERC Order No. 779. In effect, the various
balancing (BAL) standards do not include standards for emergency hydroelectric
generation or protection of equipment, such as series capacitors and static VAR
compensators (SVC), necessary to maintain voltage stability for power imported
from Canada. Without power imported from Balancing Authorities outside of ISO-
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New England, which also may be at risk of concurrent Geomagnetically-Induced
Current (GIC), reactive power consumption, and adverse harmonics, the New
England region is more likely to be at risk of prolonged electric grid blackout. The
rationale of NERC’s drafting team for excluding Balancing Authorities from
participation as responsible entities to fulfill “operating procedures” is stated in
NERC’s “Functional Entity Applicability” document, which states: “… Balancing
Authorities (BA) should not be among the applicable functional elements because
there were no additional steps or tasks for a BA to perform beyond their normal
balancing functions to mitigate GMD events.” To the contrary, as GIC equipment
monitors are already deployed within some Balancing Authorities, BA’s need to
assess the performance and GMD-related deterioration of networks during the
moderate solar geomagnetic storms in coming years. Balancing Authorities may
benefit from modeling balancing options under degraded conditions, such as the
loss of a key Static VAR Compensator. There are interplays between selection of
equipment options, and selection of balancing strategies to “operate through”
moderate level solar storms. Further, commercially available GIC monitors now
provide “operating procedure” choices for their programming. At what level
should different alarms be set, and to which entity should these alarms be
reported? BAs have a “need to know” and critical roles to play, in both advising
about equipment upgrades and in making best use of, or de-energizing as needed
equipment that impacts the ability to balance loads before, during and after a
GMD event. For further information on GIC monitors that are now available, see
the Foundation Comments of October 15, 2013 in Maine PUC Docket 2013-00415.
Moreover, if the Balancing Authorities are full-time partners in "operating
procedures" to be coordinated by the RCs, it is more likely that additional GIC
monitors will be installed at key locations, and critical equipment such as SVCs,
Extra High Voltage (EHV) transformers, and generators will be protected from
tripping or permanent damage. Also, power transmission over High Voltage Direct
Current (HVDC) ties that are vulnerable to tripping from GIC will be better planned
and protected. Already in New England, the Phase II HVDC tie from Canada has
tripped off during a solar storm. A second concern of our Foundation relates to
the arbitrary limitation of equipment to be subject to "operating procedures" to
those portions of utility networks with high-side voltage of 200 kV or higher. We
understand that the lower voltage transformers have higher resistance; hence
they are generally less susceptible to GIC entering the bulk power system. But
there are so many more transformers under 200 kV--roughly double the total
transmission mileage in the U.S. transmission infrastructure--and so many more
opportunities for "GIC leakage" into the EHV transmission networks. It appears
imprudent to exclude transformers in the 100 kV to 200 kV range from "operating
procedures." PowerWorld has estimated that less than 60% of total MVAR enters
the bulk power system through transformers at 230 kV or higher, in both New
England and in Michigan. Other regions that have not been adequately modeled
to date may also incur high "GIC leakage" from transformers with high-end
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
voltage under 200 kV. Transformers supplying these additional MVARs may
experience transmission congestion, adverse effects of harmonics through
overheating and equipment vibration, and risks of equipment damage or total
loss. The economics of "operating procedures" may well demonstrate benefits of
some combination of equipment installation and operating procedures to reduce
the rate of "GIC leakage" into the bulk power system via transmission sub-systems
operating below 200 kV. NERC has not done the financial analysis mandated by
FERC Order No. 779, so NERC should not prematurely exclude these grid pathways
subject to GMD-induced instability, unreliability, and reduced capacity utilization.
It is also notable that much of the specialized equipment designed to provide
reactive power or to stabilize voltages within design tolerances operate below 200
kV. Is this equipment to be excluded from protective "operating procedures"
under Proposed NERC Standard EOP-010-1? Siemens, for example, identifies many
Static VAR Compensators operating at less than 200 kV. CenterPoint's Crosby SVC
(IOC 2008) operates at 138 kV. Brushy Hill (1986, Canada) operates at 138 kV.
Entergy's Porter SVC in Texas (IOC 2005) operates at 138 kV. CenterPoint Energy's
Bellaire (IOC 2008) operates at 138 kV; Exelon's 2 SVCs at Elmhurst operate at 138
kV. Entergy's Prospects Heights SVC near Chicago has 2 SVCs at 138 kV.
Northeast's Glenbrook, CT STATCOM operates at 115 kV. In “Appendix 2, Detailed
Summary of Power System Impacts from March 13-14, 1989 Geomagnetic
Superstorm” of “Meta-R-319, Geomagnetic Storms and Their Impacts on the U.S.
Power Grid” by John Kappenman (January 2010, Oak Ridge National Laboratory), a
table of system impacts on Page A2-2 shows no less than 10 GIC impacts on
equipment operating at a base voltage of less than 200 kV. This is real -world data
during a moderate solar storm. In contrast, NERC offers only theorizing in its
document, “Network Applicability, Project 2013-03 (Geomagnetic Disturbance
Mitigation), EOP-010-1 (Geomagnetic Disturbance Operations), Summary
Determination” that networks operating at less than 200 kV would not be affected
by GIC. Real world data should trump the technical speculation of NERC. Networks
operating at less 200 kV (and over 100 kV) are part of the Bulk Power System and
should be included in standards for GMD mitigation. Increasingly, the Bulk Power
System is connected to wind power generation, with many wind power systems at
ocean boundaries that may import above-average GIC. Wind power systems are
generally stepped up to less than 200 kV. Wind power transmission systems are
increasingly outfitted with GIC monitors. So, if these facilities are excluded from
"operating procedures," will that mean that the near-real-time GIC data now
available to wind power operators will not be shared with the RCs? It is notable
that in the Maine PUC Docket 2013-00415, with documents retrievable via the
Internet, John Kappenman of Storm Analysis Consultants reported in October
2013 that, depending upon the orientation of a solar storm, the single GIC
monitor at Chester Maine might report little or no GIC, even in a large solar storm.
This is the only near-real-time GIC data received by ISO-New England, the relevant
RC. Why would NERC seek to exclude GIC monitors at wind generation-
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
transmission interconnections below 200 kV from "operating procedure"
management by the Regional Coordinators? This would appear to be imprudent
and is likely to result in needless risks to bulk power system reliability. In FERC
Order No. 777, 142 FERC Para 61,208, issued on March 31, 2013, FERC provided a
rationale for extending a reliability standard below 200 kV voltages under
circumstances where the assets under consideration "are critical to reliability."
See FERC Order No. 777 at p. 23, in Docket RM12-4-000. All of the SVCs,
STATCOMs, series capacitors, and prospective dynamic VAR compensators with
voltage under 200 kV should be considered as equipment "critical to reliability"
for purposes of GMD operating procedures. Finally, our Foundation is alarmed
that Generator Operators are now excluded from "operating procedure"
jurisdiction in the proposed standard. Why? The NERC Drafting Team determined
“that Generator Operators should not be among the applicable functional entities
because any operating procedure to mitigate the effects of GMD would need to
be supported by an equipment-specific study and is expected to require GMD
monitoring equipment.” We find these rationales to be implausible. Generator
Operators have, for more than a decade, utilized formulae provided (by ABB and
other vendors) to down-power generation, hence loads on unprotected EHV
transformers. There is operating experience with these “down-powering”
practices that need to be shared as “best practices” or unacceptable practices.
Those Generator Operators that already have installed GIC monitors, working with
regional models, have already produced estimated of field voltages that will or
will not collapse regional transmission networks. It would be imprudent to wait
until every Generator Operators has GIC monitors at every GSU transformer to
develop “operating procedures” that can protect critical equipment using costeffective strategies. Another reason to bring Generator Operators into “operating
procedure” practices as soon as possible is to help educate Generator Operators
to understand the practical limits of “operating procedures” for Generator
Operators with equipment running at “GIC hotspots.” Neutral ground blocking
devices not only eliminate virtually all GICs entering GSU transformer, but also
reduce vulnerabilities of other GSU transformers that are unprotected within
regional networks. The sooner executives of Generator Operators learn whether
they will benefit from hardware protecting investments, the better. See the
Foundation’s reproduction of a NOAA (Denver) initiative to display the frequency
of half-cycle solar GMD events for the period 1958-2007 (Figure 20), indicating an
above average risk in the years following solar maxima. The last solar maximum
occurred in September 2013. See the Foundation Reply Comment of October 15,
2013 in Maine PUC Docket 2013-00415. FERC’s Order No. 779 seeks expedited
protection of the bulk power system, not endless delays of needed protections.
Many Generator Operators own and operate GSU transformers that at risk for
damage due to GICs entering their GSU transformers and the bulk power system.
Some Generator Operators, e.g. NextEra, have spun-off subsidiaries that can
qualify their EHV transformers for OATTS cost-recovery by transferring ownership
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
into a closely held transmission company. In either case, Generator Operators are
key players in determining whether to downpower during a space weatherwarning period. Many Generator Operators are also aware that the harmonics
from GICs that enter their systems cause both overheating and vibrational effects
on other equipment such as: generator stators, stator cooling pipes, and
generator turbines. To exclude Generation Operators from "operating
procedures" appears unfounded and a possible aggravating factor in a severe
solar geomagnetic storm. Lastly, NERC needs to address what can be done to
protect high-cost,long-replacement-time equipment during a severe solar storm,
such as the New York Railroad storm of May 1921. Will the Nuclear Regulatory
Commission preemptively order the de-energizing of all nuclear generating
facilities and associated GSU transformers? Should the President order the deenergizing of all unprotected GSU transformers, including those without neutral
ground blocking or designs projected to survive impending GMD events? If so,
how will the Generator Operators protect their equipment, train personnel to
validate and authenticate de-energization orders, and plan for optimal "black
start" procedures? Excluding Generation Operators from the jurisdictional scope
of "operating procedures" appears to be based on the convenient but false
assumption that the only solar geomagnetic storms for which electric utilities
need prepare are those of moderate strength and short duration. We cannot in
good conscience vote "yes" for a proposed standard for "operating procedures"
that excludes Balancing Authorities, excludes Generator Operators, excludes
critical equipment operating at under 200 kV, and excludes operators of GIC
monitoring equipment from a mandate to share safety-related information in
near-real time. NERC and the electric utility industry can achieve more effective
standards. If this standard is approved by NERC as proposed, FERC should require
key modifications in its review process.
Yes
Yes
Yes
For further background information on the Foundation's support of wider
jurisdiction for coordinated "operating procedures" see our March 2013 case
study of Maine and ISO-New England in a solar geomagnetic storm, found at
www.resilientsocieties.org and the Foundation's comments responsive to queries
by the Maine Public Utilities Commission, in MPUC Docket 2013-00415 (Oct 4,
2013), and our Supplemental and Reply Comments in that same Docket (October
15, 2013).
Individual
Jen Fiegel
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Oncor Electric Delivery Company LLC
Yes
Yes
No
The Implementation Plan timeline calls for implementation 6 months from the
standard approval or on the first day following the retirement of IRO-005-3.1a.
This timeline does not provide sufficient time to create the necessary procedures
or processes and train necessary personnel to those processes and procedures.
The preferable timeline would be for implementation 12 months from the
standard approval or on the first day following the retirement of IRO-005-3.1a,
whichever is later.
No
Individual
Rich Salgo
NV Energy
Yes
Yes
Individual
Robert B Stevens
CPS Energy
No
I beleive this standard should be developed regionally, not at a national level.
No
No
Implementation should be at the regional level
No
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Monitoring
The Project 2013-03 Drafting Team thanks all commenters who submitted comments on the revised
draft stage 1 Standard (EOP-010-1). Project 2013-03 will develop requirements for registered entities to
employ strategies that mitigate risks of instability, uncontrolled separation and Cascading in the BulkPower System caused by geomagnetic disturbances (GMD) in two stages as directed by the Federal
Energy Regulatory Commission (FERC or the Commission)in Order No. 779 (Reliability Standards for
Geomagnetic Disturbances, Order No. 779, 143 FERC ¶ 61,147 (2013)(Order No. 779):
1. Stage 1 standard(s) will require applicable registered entities to develop and implement
Operating Procedures with predetermined and actionable steps to take prior to and during
GMD events which take into account entity-specific factors that can impact the severity of GMD
events in the local area.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going
assessments of the potential impact of benchmark GMD events on their respective system as
directed in Order 779. The Stage 2 standard(s) must identify benchmark GMD events that
specify what severity GMD events applicable registered entities must assess for potential
impacts. If the assessments identify potential impacts from benchmark GMD events, the
standard(s) will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of benchmark GMD events.
The standard was posted for a 45-day formal comment period from September 4, 2013 through
October 21, 2013. Stakeholders were asked to provide feedback on the standard and associated
documents through a special electronic comment form. There were 37 sets of responses, including
comments from approximately 120 individuals from approximately 80 companies representing 9 of the
10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the project page.
Summary Consideration:
The drafting team has reviewed all comments and made the following non-substantive changes to
incorporate stakeholder recommendations:
•
Section 5 (Background): Capitalized "Protection System" because it is defined in the NERC
Glossary of Terms.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
•
Requirement R1: Revised the requirement to include the term Operating Process in R1 and R1
part 1.2 and changed language to be consistent with Requirement R3. The revised requirement
with highlighted changes is as follows:
R1. Each Reliability Coordinator shall develop, maintain, and implement a GMD Operating Plan
that coordinates GMD Operating Procedures or Operating Processes within its Reliability
Coordinator Area. At a minimum, the GMD Operating Plan shall include: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning, Same-day
Operations, Real-time Operations]
1.1 A description of activities designed to mitigate the effects of GMD events on the
reliable operation of the interconnected transmission system within the Reliability
Coordinator Area.
1.2 A process for the Reliability Coordinator to review the GMD Operating Procedures
or Operating Processes of Transmission Operators within the its Reliability Coordinator
Area.
•
Measure M1: Inserted the word “current” to conform to NERC guidelines for writing Measures
to support this type of Requirement. The revised measure with highlighted change is as follows:
M1. Each Reliability Coordinator shall have a current GMD Operating Plan meeting all the
provisions of Requirement R1; evidence such as a review or revision history to indicate
that the GMD Operating Plan has been maintained; and evidence to show that the plan
was implemented as called for in its GMD Operating Plan, such as dated operator logs,
voice recordings, or voice transcripts.
•
Requirement R2: Clarified that the Reliability Coordinator shall disseminate forecasted and
current space weather information to functional entities identified as recipients in the Reliability
Coordinator's GMD Operating Plan. The revised requirement with highlighted change is as
follows:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information to functional entities identified as recipients as specified in the Reliability
Coordinator's GMD Operating Plan. [Violation Risk Factor: Medium] [Time Horizon: Sameday Operations, Real-time Operations]
•
Requirement R3: Inserted the word GMD, so that the phrase "GMD Operating Procedure or
Operating Process" would be consistent with Requirement R1. The revised requirement is as
follows:
R3. Each Transmission Operator shall develop, maintain, and implement a GMD Operating
Procedure or Operating Process to mitigate the effects of GMD events on the reliable
operation of its respective system. At a minimum, the Operating Procedure or Operating
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning,
Operations Planning, Same-day Operations, Real-Time Operations]
•
Implementation Plan. A clarifying change was made to the Implementation Plan to conform to
the effective date language in the standard, which was changed in the prior draft in response to
concerns raised by Canadian entities.
A summary response to each comment follows each question. Please note that because common
issues were grouped together in the summaries, an individual's comment may have been addressed in
the summary for a question that is different from the question in which they submitted the comment;
the drafting team encourages reviewers to read all summary responses.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Index to Questions, Comments, and Responses
1.
The drafting team has revised EOP-010-1 in response to stakeholder comments. Changes include
removing the BA from applicability, clarifying applicability for TOPs, adding a Requirement for
RCs to disseminate space weather information, removal of administrative requirements that do
not benefit reliability, and clarifying changes to the language of requirements and measures. Do
you agree that the revised standard correctly addresses the Stage 1 directives of Order No. 779
and is acceptable? If you do not agree or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments................... 13
2.
Do you agree that the VRFs and VSLs support the reliability objectives of the standard and meet
FERC and NERC guidelines? If you do not agree or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments. .. 31
3.
The Implementation Plan provides conditions for determining when the Requirements in EOP010-1 become effective in each jurisdition. Do you agree with the Implementation Plan as
written? If you do not agree or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments................................... 35
4.
If you have any other comments for the drafting team to consider that you haven’t already
mentioned, please provide them here: .......................................................................................... 38
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
4
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
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Frank Gaffney
Additional Member
1.
2.
3.
4.
5.
6.
7.
2.
Florida Municipal Power Agency
Additional Organization
Region
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Cairo Vanegas
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Stanley Rzad
Keys Energy Services
FRCC
3
Guy Zito
3
X
4
X
5
X
6
7
8
9
10
X
Segment Selection
Timothy Beyrle
Group
X
2
Northeast Power Coordinating Council
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
3.
Additional Member
Alan Adamson
Greg Campoli
Sylvain Clermont
Chris de Graffenried
Gerry Dunbar
Peter Yost
Kathleen Goodman
Michael Jones
Mark Kenny
Christina Koncz
Helen Lainis
Michael Lombardi
Randy MacDonald
Bruce Metruck
Silvia Parada Mitchell
Lee Pedowicz
Robert Pellegrini
Si-Truc Phan
Brian Robinson
Brian Shanahan
Wayne Sipperly
Ayesha Sabouba
David Ramkalawan
Ben Wu
Group
Additional Organization
New York State Reliability Council, LLC
New York Independent System Operator
Hydro-Quebec TransEnergie
Consolidated Edison Co. of New York, Inc.
Northeast Power Coordinating Council
Consolidated Edison Co. of New York, Inc.
ISO - New England
National Grid
Northeast Utilities
PSEG Power LLC
Independent Electricity System Operator
Northeast Power Coordinating Council
New Brunswick Power Transmission
New York Power Authority
NextEra Energy, LLC
Northeast Power Coordinating Council
The United Illuminating Company
Hydro-Quebec TransEnergie
Utility Services
National Grid
New York Power Authority
Hydro One Networks Inc.
Ontario Power Generation, Inc.
Orange and Rockland Utilities
Connie Lowe
NERC Compliance Policy
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
Region
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
2
Segment Selection
10
2
1
1
10
3
2
1
1
5
2
10
9
6
5
10
1
1
8
1
5
1
5
1
X
3
X
4
5
X
6
X
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
2.
3.
4.
4.
1.
2.
3.
4.
5.
6.
5.
1.
2.
3.
4.
5.
6.
7.
8.
9.
2
Additional Organization Region Segment Selection
Dominion
SERC
1, 3, 5, 6
Dominion
NPCC 5, 6
Dominion
RFC
5, 6
Dominion
MRO 5, 6
Associated Electric Cooperative, Inc. X
Group
David Dockery
JRO00088
Additional Member
Additional Organization Region Segment Selection
Central Electric Power Cooperative
SERC
1, 3
KAMO Electric Cooperative
SERC
1, 3
M & A Electric Power Cooperative
SERC
1, 3
Northeast Missouri Electric Power
SERC
1, 3
Cooperative
N.W. Electric Power Cooperative, Inc.
SERC
1, 3
Sho-Me Power Electric Cooperative
SERC
1, 3
X
Group
Sammy Roberts
SERC OC Review Group
3
4
5
6
Additional Member
Michael Crowley
Mike Garton
Louis Slade
Randi Heise
Additional Member
James Case
William Berry
Gerald Beckerle
Gary Kobet
Michael Lowman
Terry Bilke
Phil D'Antonio
Patrick McGovern
Marsha Morgan
Additional Organization
Entergy
OMU
Ameren
TVA
Duke Energy
MISO
PJM Interconnection
Georgia Transmission Corporation
Southern Company
Region
SERC
SERC
SERC
SERC
SERC
SERC
SERC
SERC
SERC
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
X
X
X
X
X
X
Segment Selection
1, 3, 6
3
1, 3
1, 3, 5, 6
1, 3, 5, 6
2
2
1
1, 5
7
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. Tom Pruitt
6.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
7.
1.
2.
3.
4.
8.
Duke Energy
SERC
3
4
5
6
1, 3, 5, 6
Group
Robert Rhodes
SPP Standards Review Group
Additional Member
Additional Organization
Region
Kevin Frick
Westar Energy
SPP
Louis Guidry
Cleco Power LLC
SPP
Michael Herzog
Omaha Public Power District
MRO
Stephanie Johnson
Westar Energy
SPP
Bo Jones
Westar Energy
SPP
Richard Kalina
Omaha Public Power District
MRO
Dong-Hyeon Kim
Burns & McDonnell
NA - Not Applicable
Allen Klassen
Westar Energy
SPP
Jeff Knottek
City Utilities of Springfield
SPP
Tiffany Lake
Westar Energy
SPP
Greg McAuley
Oklahoma Gas & Electric
SPP
James Nail
City of Independence, MO
SPP
Mahmood Safi
Omaha Public Power District
MRO
Bryan Taggart
Westar Energy
SPP
Scott Williams
City Utilities of Springfield
SPP
X
Segment Selection
1, 3, 5, 6
1, 3, 5
1, 3, 5
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5
NA
1, 3, 5, 6
1, 4
1, 3, 5, 6
1, 3, 5
3
1, 3, 5
1, 3, 5, 6
1, 4
X
Group
Colby Bellville
Duke Energy
Additional Member
Additional Organization Region Segment Selection
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC 3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
ISO/RTO Council Standards Review
Group
Greg Campoli
Committee
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
2
X
X
X
X
8
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
2.
3.
4.
5.
6.
7.
Additional Member
Kathleen Goodman
Charles Yeung
Ali Miremadi
Terry Bilke
Al DiCaprio
Cheryl Moseley
Ben Li
Additional Organization
ISO-NE
SPP
CAISO
MISO
PJM
ERCOT
IESO
Region
NPCC
SPP
WECC
MRO
RFC
ERCOT
NPCC
X
Group
Don Hargrove
Oklahoma Gas & Electric
Additional Member
Additional Organization Region Segment Selection
1. Terri Pyle
OG&E
SPP
1
2. Leo Staples
OG&E
SPP
5
3. Jerry Nottnagel
OG&E
SPP
6
Group
Additional
Member
1. Bill Hutchison
2. John Shaver
3. Shari Heino
4. Scott Brame
5. Megan Wagner
Ben Engelby
3
4
5
6
Segment Selection
2
2
2
2
2
2
2
9.
10.
2
11.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
X
Segment
Selection
SERC
1
WECC
1, 4, 5
ERCOT
RFC
SPP
1, 5
1, 3, 4, 5
1
X
Group
Jamison Dye
Bonneville Power Administration
Additional Member
Additional Organization Region Segment Selection
1. Dan Goodrich
Technical Operations
WECC 1
2. Ran Xu
Technical Operations
WECC 1
X
X
ACES Standards Collaborators
Additional Organization
Region
Southern Illinois Power Cooperative
Arizona Electric Power Cooperative/Southwest
Transmission Cooperative, Inc.
Brazos Electric Power Cooperative, Inc.
North Carolina Electric Membership Corporation
Sunflower Electric Power Corporation
X
X
X
X
9
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
X
3
X
X
X
X
X
X
X
X
X
Janet Smith
Arizona Public Service Co.
13.
Individual
Ryan Millard
PacifiCorp
14.
Individual
Kaleb Brimhall
Colorado Springs Utilities
X
15.
Individual
Wayne Johnson
Southern Company
X
16.
Individual
Erika Doot
US Bureau of Reclamation
X
17.
Individual
William R. Harris
Foundation for Resilient Societies
18.
Individual
Nazra Gladu
Manitoba Hydro
19.
Individual
Ayesha Sabouba
Hydro One
20.
Individual
Thomas Foltz
American Electric Power
21.
Individual
Anthony Jablonski
X
X
Individual
Kenn Backholm
ReliabilityFirst
Public Utility District No.1 of Snohomish
County
23.
Individual
John Seelke
Public Service Enterprise Group
X
X
24.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
25.
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
X
26.
Individual
Phil Anderson
Idaho Power
X
27.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
28.
Individual
Michael Falvo
Independent Electricity System Operator
X
29.
Individual
Kathleen Goodman
ISO New England Inc.
X
30.
Individual
Richard Vine
California ISO
X
31.
Individual
Alice Ireland
Xcel Energy
32.
Individual
Don Schmit
Nebraska Public Power District
33.
Individual
Cheryl Moseley
Individual
Sergio Banuelos
Electric Reliability of Texas, Inc.
Tri-State Generation and Transmission
Association, Inc.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
6
X
Individual
34.
5
X
12.
22.
4
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
35.
Individual
Jen Fiegel
Oncor Electric Delivery Company LLC
X
36.
Individual
Rich Salgo
NV Energy
X
37.
Individual
Robert B Stevens
CPS Energy
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
2
3
X
4
5
X
X
11
6
7
8
9
10
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Organization
Supporting Comments of “Entity Name”
ISO New England Inc.
IRC SRC
Colorado Springs Utilities
NA
Southern Company
SERC OC
Associated Electric Cooperative,
Inc. - JRO00088
SERC OC Review Group
South Carolina Electric and Gas
SERC Operating Committee (OC)
California ISO
The ISO supports the comments submitted by the ISO/RTO Standards Review Committee
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
12
1. The drafting team has revised EOP-010-1 in response to stakeholder comments. Changes include removing the BA from
applicability, clarifying applicability for TOPs, adding a Requirement for RCs to disseminate space weather information, removal
of administrative requirements that do not benefit reliability, and clarifying changes to the language of requirements and
measures. Do you agree that the revised standard correctly addresses the Stage 1 directives of Order No. 779 and is acceptable?
If you do not agree or you agree in general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on the revised EOP-010-1. All comments have been reviewed
and changes that the drafting team considers appropriate were incorporated into a subsequent revision. A summary of comments and
the drafting team's response is provided:
•
•
•
Consistent language between Requirement R1 and Requirement R3 in describing the required operating measures as
"Operating Procedures or Operating Processes." Commenters recommended that Requirement R1 and Requirement R1 part
1.2 include language that matches Requirement R3. The drafting team has made this clarifying change in the final revision.
Unclear or implied requirements for the Reliability Coordinator to include space weather information in the GMD Operating
Plan. Some commenters stated that the requirement was unclear; some recommended that the requirement specifically
state what information should be disseminated or what recipients it should be disseminated to. Some commenters did not
believe the requirement was necessary. The drafting team's intent with Requirement R2 is to maintain the Reliability
Coordinator's existing obligation to disseminate space weather information as specified in IR0-005-3.1a Requirement R3. IRO005-4 has been adopted by the NERC Board and filed with FERC, and will retire IRO-005-3.1a Requirement R3. To clarify this
intent, the final version of EOP-010-1 Requirement R2 states that the Reliability Coordinator will disseminate space weather
information to functional entities identified as recipients in the Reliability Coordinator's GMD Operating Plan. The drafting team
believes Requirement R1 and Requirement R2 provide the Reliability Coordinator with appropriate flexibility to tailor its GMD
Operating Plan to promote consistent awareness of space weather information in the Reliability Coordinator Area.
Requirements for the RC to coordinate GMD Operating Procedures and Operating Processes. Commenters stated that R1
needed to be more specific about how coordination should occur. Some commenters stated that Requirement R1 should be
expanded to specifically address recourse when the RC required changes to a TOPs Operating Procedures or Operating
Processes after review. The drafting team believes that Requirement R1 as written describes the essential elements to assure
coordination and is consistent with the roles described in the NERC Functional Model. The drafting team did not believe that the
suggestion to replace "coordinate" with "affirm the compatibility of" in Requirement R1 improved clarity. Coordination is
intended to ensure that Operating Procedures within a Reliability Coordinator Area are not in conflict with one another; it is not
intended to be a review by the Reliability Coordinator of the technical aspects of the GMD Operating Procedures or Operating
Processes. The Transmission Operator is responsible for the technical aspects of its Operating Procedures or Operating
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
13
•
•
Processes pursuant to Requirement R3. For example, if Company A submitted an Operating Procedure proposing to take Line X
out of service at specified GMD conditions and Company B submitted an Operating Procedure that relies on Line X remaining in
service in the event of a GMD -- it is the responsibility of the Reliability Coordinator to identify this conflict. The Reliability
Coordinator would then require Company A and Company B to resolve this conflict and resubmit their Operating
Procedures. The drafting team believes that the coordination and resolution of identified operating conflicts can be resolved
using existing agreements and processes.
Applicability to all networks greater than 200 kV with grounded-wye transformers. Some commenters indicated that 300 kV
threshold is the appropriate voltage threshold based on the Oak Ridge National Labs report or other unspecified utility
research. Another commenter stated that the 200 kV minimum voltage threshold was imprudent because a large population
of transformers would not be covered or protected by the operating procedures, and that an unacceptable opportunity for
GIC to enter the transmission network was permitted. One commenter recommended alternate wording in the applicability
section. One commenter reiterated earlier comments that the applicability should be limited to single-phase transformers.
The drafting team believes the applicability section is worded clearly and would not be improved with the suggested wording.
The drafting team agrees that single-phase transformers are more susceptible to half-cycle saturation due to GIC than threephase three-limb core units, but does not agree that core construction is appropriate for use in determining applicability.
Reactive power absorption in three-phase three-limb core units could have system impacts in some networks.
The effect of GIC in networks less than 200 kV has negligible impact on the reliability of the interconnected transmission system.
Using a voltage threshold higher than 200 kV could potentially create a reliability gap in many systems by excluding from the
reliability standard a portion of the network that can be affected by GMD. Establishing 200 kV as the lower-bound threshold is
consistent with operating experience and modeling guidance provided in the peer-reviewed technical literature. The drafting
team's technical justification for establishing a 200 kV threshold in the applicability of EOP-010-1 is posted to the project page.
(http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx ).
Applicable functional entities.
o Balancing Authority. A commenter stated that Balancing Authorities needed to be included as an applicable
functional entity in order for the RC to effectively coordinate Operating Procedures. The SDT agrees that Balancing
Authorities have a role in GMD response, as with many other reliability risks. This role is adequately covered by the
real-time responsibilities described in the NERC Functional Model and as required by other Reliability Standards.
o Generator Operator. Some commenters stated that Generator Operators should be included in the standard. The
SDT agrees that Generator Operators have a role in GMD response as with many other reliability risks. This role is
adequately covered by the real-time responsibilities described in the NERC Functional Model and as required by other
Reliability Standards. Generator Operators may be included in stage 2 standards.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
14
•
•
•
•
Transmission Operator. One commenter indicated that the standard should apply to the RC only. The functional model states
that the Transmission Operator has responsibility and authority for the reliable operation of the transmission system within the
Transmission Operator Area. Applicability of EOP-010-1 to the Transmission Operator is consistent with this responsibility and
authority.
Time horizons. Some commenters recommended changes to time horizons, or additions to the rationale box to clarify the
drafting team's intent. When requirements include performance elements that take place over different time horizons, it is
acceptable to include more than one time horizon. The drafting team clarifies that development of the GMD Operating Plans,
Processes, or Procedures occurs in the Long-Term Planning Time Horizon, which is defined as a planning horizon of one year or
longer. Maintenance of the GMD Operating Plans, Processes, or Procedures occurs in the Operations Planning Time Horizon.
Implementation of GMD Operating Plans, Processes, or Procedures occurs in the Operations Planning, Same-Day and Real-Time
Time Horizons depending on the activity. The drafting team did not agree with a comment that suggested removal of the Longterm Planning Time Horizon from Requirements R1 and R3. The drafting team agrees that this type of planning could occur in
the Operations Planning time horizon, but because space weather follows an 11-year solar cycle it could also be viewed by an
entity from a long-term planning perspective.
Alternate approaches using existing standards. Some commenters stated that existing standards already manage GMD
impacts. Order No. 779 directs NERC to develop new reliability standards or modify existing requirements to mitigate the risk of
GMD. The SDT chose to develop new reliability standards as the most efficient means of providing improved reliability during
GMD events, although the team has recognized that existing standards are related to EOP-010-1, as noted herein.
Additions to Requirements or new Requirements. A small number of commenters suggested substantive changes and the
drafting team does not believe there is consensus support for substantive changes. For example, one commenter suggested
that EOP-010-1 should be developed regionally, rather than as a continent-wide standard. The drafting team believes that the
approach in the standard is appropriate to ensure a common level of preparedness for GMD events continent-wide, while at the
same time allowing flexibility for each entity to tailor its procedures and plans to account for regional and local considerations.
Organization
Yes or No
Question 1 Comment
CPS Energy
No
I beleive this standard should be developed regionally, not at a national level.
Flathead Electric
Cooperative, Inc.
No
I believe that either this standard should only apply to the RC or the stage 1 directives
should be addressed outside the standards process. Recent GDM events have shown
little to no impact on the Bulk Electric System and creating a GDM Operating Plan
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
15
Organization
Yes or No
Question 1 Comment
requirement and auditing process is likely to have little reliability impact other than
blindly following the letter of these directives.
Foundation for
Resilient Societies
No
Question 1:Our Foundation's Case Study on Maine and ISO New England's capacity to
mitigate a severe solar geomagnetic storm (March 2013 - found on website
www.resilientsocieties.org) reaffirmed our prior understanding that the Regional
Coordinators (in this case ISO-New England) cannot adequately coordinate "operating
procedures" to mitigate a severe GMD event without concurrent jurisdiction over
Balancing Authorities (BAs) and Generator Operators (GOs). In a severe solar storm, the
combination of generation reserves together with demand response reserves may not
enable Regional Coordinators (RCs) to balance loads without active preparation and
support of balancing authorities. For ISO-New England that would include Canadian
resources and balancing operators beyond the authority and scope of FERC Order No.
779. In effect, the various balancing (BAL) standards do not include standards for
emergency hydroelectric generation or protection of equipment, such as series
capacitors and static VAR compensators (SVC), necessary to maintain voltage stability
for power imported from Canada. Without power imported from Balancing Authorities
outside of ISO-New England, which also may be at risk of concurrent GeomagneticallyInduced Current (GIC), reactive power consumption, and adverse harmonics, the New
England region is more likely to be at risk of prolonged electric grid blackout. The
rationale of NERC’s drafting team for excluding Balancing Authorities from participation
as responsible entities to fulfill “operating procedures” is stated in NERC’s “Functional
Entity Applicability” document, which states:”... Balancing Authorities (BA) should not
be among the applicable functional elements because there were no additional steps or
tasks for a BA to perform beyond their normal balancing functions to mitigate GMD
events.”To the contrary, as GIC equipment monitors are already deployed within some
Balancing Authorities, BA’s need to assess the performance and GMD-related
deterioration of networks during the moderate solar geomagnetic storms in coming
years. Balancing Authorities may benefit from modeling balancing options under
degraded conditions, such as the loss of a key Static VAR Compensator. There are
interplays between selection of equipment options, and selection of balancing
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
16
Organization
Yes or No
Question 1 Comment
strategies to “operate through” moderate level solar storms. Further, commercially
available GIC monitors now provide “operating procedure” choices for their
programming. At what level should different alarms be set, and to which entity should
these alarms be reported? BAs have a “need to know” and critical roles to play, in both
advising about equipment upgrades and in making best use of, or de-energizing as
needed equipment that impacts the ability to balance loads before, during and after a
GMD event. For further information on GIC monitors that are now available, see the
Foundation Comments of October 15, 2013 in Maine PUC Docket 201300415.Moreover, if the Balancing Authorities are full-time partners in "operating
procedures" to be coordinated by the RCs, it is more likely that additional GIC monitors
will be installed at key locations, and critical equipment such as SVCs, Extra High
Voltage (EHV) transformers, and generators will be protected from tripping or
permanent damage. Also, power transmission over High Voltage Direct Current (HVDC)
ties that are vulnerable to tripping from GIC will be better planned and protected.
Already in New England, the Phase II HVDC tie from Canada has tripped off during a
solar storm.A second concern of our Foundation relates to the arbitrary limitation of
equipment to be subject to "operating procedures" to those portions of utility networks
with high-side voltage of 200 kV or higher. We understand that the lower voltage
transformers have higher resistance; hence they are generally less susceptible to GIC
entering the bulk power system. But there are so many more transformers under 200
kV--roughly double the total transmission mileage in the U.S. transmission
infrastructure--and so many more opportunities for "GIC leakage" into the EHV
transmission networks. It appears imprudent to exclude transformers in the 100 kV to
200 kV range from "operating procedures."PowerWorld has estimated that less than
60% of total MVAR enters the bulk power system through transformers at 230 kV or
higher, in both New England and in Michigan. Other regions that have not been
adequately modeled to date may also incur high "GIC leakage" from transformers with
high-end voltage under 200 kV. Transformers supplying these additional MVARs may
experience transmission congestion, adverse effects of harmonics through overheating
and equipment vibration, and risks of equipment damage or total loss. The economics
of "operating procedures" may well demonstrate benefits of some combination of
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
17
Organization
Yes or No
Question 1 Comment
equipment installation and operating procedures to reduce the rate of "GIC leakage"
into the bulk power system via transmission sub-systems operating below 200 kV.
NERC has not done the financial analysis mandated by FERC Order No. 779, so NERC
should not prematurely exclude these grid pathways subject to GMD-induced
instability, unreliability, and reduced capacity utilization. It is also notable that much of
the specialized equipment designed to provide reactive power or to stabilize voltages
within design tolerances operate below 200 kV. Is this equipment to be excluded from
protective "operating procedures" under Proposed NERC Standard EOP-010-1?
Siemens, for example, identifies many Static VAR Compensators operating at less than
200 kV. CenterPoint's Crosby SVC (IOC 2008) operates at 138 kV. Brushy Hill (1986,
Canada) operates at 138 kV. Entergy's Porter SVC in Texas (IOC 2005) operates at 138
kV. CenterPoint Energy's Bellaire (IOC 2008) operates at 138 kV; Exelon's 2 SVCs at
Elmhurst operate at 138 kV. Entergy's Prospects Heights SVC near Chicago has 2 SVCs
at 138 kV. Northeast's Glenbrook, CT STATCOM operates at 115 kV.In “Appendix 2,
Detailed Summary of Power System Impacts from March 13-14, 1989 Geomagnetic
Superstorm” of “Meta-R-319, Geomagnetic Storms and Their Impacts on the U.S. Power
Grid” by John Kappenman (January 2010, Oak Ridge National Laboratory), a table of
system impacts on Page A2-2 shows no less than 10 GIC impacts on equipment
operating at a base voltage of less than 200 kV. This is real -world data during a
moderate solar storm. In contrast, NERC offers only theorizing in its document,
“Network Applicability, Project 2013-03 (Geomagnetic Disturbance Mitigation), EOP010-1 (Geomagnetic Disturbance Operations), Summary Determination” that networks
operating at less than 200 kV would not be affected by GIC. Real world data should
trump the technical speculation of NERC. Networks operating at less 200 kV (and over
100 kV) are part of the Bulk Power System and should be included in standards for GMD
mitigation.Increasingly, the Bulk Power System is connected to wind power generation,
with many wind power systems at ocean boundaries that may import above-average
GIC. Wind power systems are generally stepped up to less than 200 kV. Wind power
transmission systems are increasingly outfitted with GIC monitors. So, if these facilities
are excluded from "operating procedures," will that mean that the near-real-time GIC
data now available to wind power operators will not be shared with the RCs? It is
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
18
Organization
Yes or No
Question 1 Comment
notable that in the Maine PUC Docket 2013-00415, with documents retrievable via the
Internet, John Kappenman of Storm Analysis Consultants reported in October 2013
that, depending upon the orientation of a solar storm, the single GIC monitor at Chester
Maine might report little or no GIC, even in a large solar storm. This is the only nearreal-time GIC data received by ISO-New England, the relevant RC. Why would NERC
seek to exclude GIC monitors at wind generation-transmission interconnections below
200 kV from "operating procedure" management by the Regional Coordinators? This
would appear to be imprudent and is likely to result in needless risks to bulk power
system reliability. In FERC Order No. 777, 142 FERC Para 61,208, issued on March 31,
2013, FERC provided a rationale for extending a reliability standard below 200 kV
voltages under circumstances where the assets under consideration "are critical to
reliability." See FERC Order No. 777 at p. 23, in Docket RM12-4-000. All of the SVCs,
STATCOMs, series capacitors, and prospective dynamic VAR compensators with voltage
under 200 kV should be considered as equipment "critical to reliability" for purposes of
GMD operating procedures.Finally, our Foundation is alarmed that Generator
Operators are now excluded from "operating procedure" jurisdiction in the proposed
standard. Why?The NERC Drafting Team determined “that Generator Operators should
not be among the applicable functional entities because any operating procedure to
mitigate the effects of GMD would need to be supported by an equipment-specific
study and is expected to require GMD monitoring equipment.”We find these rationales
to be implausible. Generator Operators have, for more than a decade, utilized
formulae provided (by ABB and other vendors) to down-power generation, hence loads
on unprotected EHV transformers. There is operating experience with these “downpowering” practices that need to be shared as “best practices” or unacceptable
practices. Those Generator Operators that already have installed GIC monitors,
working with regional models, have already produced estimated of field voltages that
will or will not collapse regional transmission networks. It would be imprudent to wait
until every Generator Operators has GIC monitors at every GSU transformer to develop
“operating procedures” that can protect critical equipment using cost-effective
strategies. Another reason to bring Generator Operators into “operating procedure”
practices as soon as possible is to help educate Generator Operators to understand the
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
practical limits of “operating procedures” for Generator Operators with equipment
running at “GIC hotspots.” Neutral ground blocking devices not only eliminate virtually
all GICs entering GSU transformer, but also reduce vulnerabilities of other GSU
transformers that are unprotected within regional networks. The sooner executives of
Generator Operators learn whether they will benefit from hardware protecting
investments, the better. See the Foundation’s reproduction of a NOAA (Denver)
initiative to display the frequency of half-cycle solar GMD events for the period 19582007 (Figure 20), indicating an above average risk in the years following solar maxima.
The last solar maximum occurred in September 2013. See the Foundation Reply
Comment of October 15, 2013 in Maine PUC Docket 2013-00415. FERC’s Order No.
779 seeks expedited protection of the bulk power system, not endless delays of needed
protections. Many Generator Operators own and operate GSU transformers that at risk
for damage due to GICs entering their GSU transformers and the bulk power system.
Some Generator Operators, e.g. NextEra, have spun-off subsidiaries that can qualify
their EHV transformers for OATTS cost-recovery by transferring ownership into a closely
held transmission company. In either case, Generator Operators are key players in
determining whether to downpower during a space weather-warning period. Many
Generator Operators are also aware that the harmonics from GICs that enter their
systems cause both overheating and vibrational effects on other equipment such as:
generator stators, stator cooling pipes, and generator turbines. To exclude Generation
Operators from "operating procedures" appears unfounded and a possible aggravating
factor in a severe solar geomagnetic storm. Lastly, NERC needs to address what can be
done to protect high-cost,long-replacement-time equipment during a severe solar
storm, such as the New York Railroad storm of May 1921. Will the Nuclear Regulatory
Commission preemptively order the de-energizing of all nuclear generating facilities and
associated GSU transformers? Should the President order the de-energizing of all
unprotected GSU transformers, including those without neutral ground blocking or
designs projected to survive impending GMD events? If so, how will the Generator
Operators protect their equipment, train personnel to validate and authenticate deenergization orders, and plan for optimal "black start" procedures? Excluding
Generation Operators from the jurisdictional scope of "operating procedures" appears
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
to be based on the convenient but false assumption that the only solar geomagnetic
storms for which electric utilities need prepare are those of moderate strength and
short duration.We cannot in good conscience vote "yes" for a proposed standard for
"operating procedures" that excludes Balancing Authorities, excludes Generator
Operators, excludes critical equipment operating at under 200 kV, and excludes
operators of GIC monitoring equipment from a mandate to share safety-related
information in near-real time. NERC and the electric utility industry can achieve more
effective standards. If this standard is approved by NERC as proposed, FERC should
require key modifications in its review process.
Public Service
Enterprise Group
No
R2 states “Each Reliability Coordinator shall disseminate forecasted and current space
weather information as specified in the Reliability Coordinator's GMD Operating Plan.”
We agree, but in R1 which requires such a plan, there is not requirement related to R2.
We believe R1 should have subpart 1.1 rewritten as follows:1.1 A description of
activities designed to mitigate the effects of GMD events on the reliable operation of
the interconnected transmission system within the Reliability Coordinator Area WHICH
INCLUDE AN ACTIVITY TO DISSEMINATE FORECASTED AND CURRENT SPACE WEATHER
INFORMATION.
SPP Standards Review
Group
No
We propose changing the wording in Section 4.1.2 under Applicability to
read:Transmission Operator with a Transmission Operator Area that includes a power
transformer with a high-side, wye-grounded winding with a terminal voltage greater
than 200 kV.This clarifies that the 200 kV winding is the high-side, wye-grounded
winding.We suggest changing the ‘the Reliability Coordinator Area’ to ‘its Reliability
Coordinator Area’ in R1.2.We suggest replacing ‘respective system’ with ‘Transmission
Operator Area’ in R3. This language would then parallel that of R1.
American Electric
Power
No
While AEP welcomes the removal of the word “coordinate” as an action performed by
the RC, the word is now used as something that is done by the Operating Plan. Despite
this change, and because the RC is required to implement the Operating Plan, there still
appears to be an “implied” obligation where the RC must coordinate. This term remains
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
vague, and more specific text should be used in its place such as “affirm the
compatibility of Operating Procedures and Operating Processes among the entities
within the Reliability Coordinator Area.”Operating Plans developed by Reliability
Coordinators may be quite different from area to area, which may be necessary in some
circumstances. However, because AEP serves in multiple Operating Regions, we hope
that the various Operating Plans, when feasible, are uniform for the most part. R1
states that the Operating Plan must coordinate GMD Operating Procedures, but makes
no mention of the Operating Process as required in R3. Similarly, R1.2 requires a
process to review GMD Operating Procedures but again makes no mention of reviewing
Operating Processes. We recommend adding “Operating Processes” in R1 and R1.2, so
that R1 reads “Each Reliability Coordinator shall develop, maintain, and implement a
GMD Operating Plan that coordinates GMD Operating Procedures or Operating
Processes within its Reliability Coordinator Area.” and that R1.2 reads “A process for the
Reliability Coordinator to review the GMD Operating Procedures or Operating
Processes of Transmission Operators in the Reliability Coordinator Area.”
Independent
Electricity System
Operator
Yes
(1) We agree with all the proposed changes, and commend the SDT for responding
positively to industry comments especially those that propose removal of the P.81 type
of requirements, and the apparent redundancy/overlap with IRO-005-3.1a, R3.
However, we believe Part 1.2 should be expanded to convey the need for developing
recourse. Part 1.2 stipulates that the RC’s GMD Operating Plan shall include:1.2. A
process for the Reliability Coordinator to review the GMD Operating Procedures of
Transmission Operators in the Reliability Coordinator Area.When a RC’s review of the
TO’s operating procedures finds something lacking, then the recourse to make
corrections should be made more clear. We suggest Part 1.2 be revised as follows:1.2. A
process for the Reliability Coordinator to review the GMD Operating Procedures of
Transmission Operators in the Reliability Coordinator Area, and direct the Transmission
Operators to correct deficiencies, if any.If the SDT accepts this recommendation, please
make a mirror change in R3 that will require the TOP to comply with the RC’s directive
for correcting the deficiencies.(2) R2 as written is unclear on to whom the weather
condition is to be provided. We suggest R2 to be clear that the RC is disseminating
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
space weather information to TOPs, as stated in the Background Information in the
Comment Form “A new Requirement R2 has been added to the standard, which would
require RCs to disseminate space weather forecast information to TOPs in the Reliability
Coordinator Area (RCA).(3) R3 - The term ‘Operating Process’ is unnecessary and
inconsistent with the wording in R1. We suggest to remove “or Operating Process” from
R3 in the statement “Each Transmission Operator shall develop, maintain, and
implement an Operating Procedure or Operating Process...”.
ACES Standards
Collaborators
Yes
1) The draft standard is much improved over the previous version. We thank the
drafting team for removing the administrative requirements and removing BA
applicability. We also agree that the standard does address the FERC directive.
However, we believe there is another option that is as equally effective, is actually more
efficient than writing a new standard and eliminates the redundancy that this proposed
standard creates. The other option is to rely on existing standards. TOP-001-1a R2 and
R8 already require the TOP to take immediate actions to alleviate operating
emergencies and to restore reactive power balance. TOP-002-2.1b R8 requires the TOP
to plan to meet voltage and/or reactive limits, including the deliverability/capability for
any single Contingency. TOP-004-2 R6.1 requires the TOP to have policies and
procedures for monitoring and controlling voltage levels and reactive power flows.
EOP-001-2 R2.2 requires the TOP to “develop, maintain, and implement a set of plans
to mitigate operating emergencies on the transmission system.” IRO-014-1 R1 requires
the RC to have operating procedures, processes or plans for activities that require
notification or exchange of information with other reliability coordinators. Since the
electric industry already takes an “all hazards” approach to planning the operation of
the grid, the RCs in geographies with greater risks to GMD events should be able to rely
on existing processes, procedures and plans to coordinate responses to GMD events.
The electric industry’s excellent response to large events such as hurricanes has proven
the “all hazards” approach to planning is effective. Since these standards requirements
are applicable at all times including during GMD events, the proposed requirements will
create an opportunity for double jeopardy due to the redundancy in the requirements.
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
Hydro One
Yes
A process for the RC to review the GMD Operating Procedures of TOs in the RCA from
the point of view of coordination is needed.
Colorado Springs
Utilities
Yes
o Thank you for your efforts. The standard drafting team has not provided sufficient
technical justification for the 200 kV threshold. Utility research indicates that the
threshold should begin more around the 300kV threshold.
Electric Reliability of
Texas, Inc.
Yes
ERCOT generally supports the SDT's efforts in developing the draft GMD standard and
believes it is on the right track. However, the SDT should consider the following
comments in the development of future versions.Most of the requirements seem to be
concentrating upon the administration of “having procedures”. The standard should
say “what” is required, while minimizing the required administration activities.1)
Applicability Section The SDT should consider the role of GOPs in the standard. The
standard in both its initial and revised form does not address the GOP function. GOPs
may have GMD operating plans in place. As the whitepaper on applicable functions
noted - “Some GOPs already have GMD Operating Procedures for their equipment
based on prior studies and/or monitoring equipment. EOP-010-1 will not prohibit or
interfere with a GOP's established procedure.” Given that generators may have GMD
procedures in place, the standard should reflect those procedures on a stand alone
basis and as inputs into the larger operational GMD procedures. The failure to consider
those plans in developing and coordinating the broader scope operational plans would
create a disconnect between core operational roles. Such disconnects could undermine
the effective and efficient management of GMD events potentially creating an
undesirable reliability impact on the interconnection. Accordingly, the SDT should
consider revisions to include the GOP function to ensure generator GMD procedures
are considered and reflected in the larger scope GMD operational procedures. These
plans should be coordinated with the relevant TOP and RC plans in a coordinated
manner that is ultimately overseen by the RC, as proposed in the standard. 2)
Requirement 1.2 The revised standard removes the coordination/compatibility
determination role of the RC. It seems the RC should be performing these roles to
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
ensure effective and efficient operations in the context of a GMD event. It is not clear
that a simple “review” role is adequate to achieve that outcome. The SDT should
reconsider whether the RC should have the ability/authority to address any potential
conflicts in plans pursuant to a coordination/compatibility determination role. If the
revision was intended to simply be a “clean-up” edit, and that the coordination role is
adequately covered in the R1 coordination role, R1 should reference R 1.2, so it is clear
that the plans referenced in R1 are defined in terms of the specific functional entity
referenced in R1.2.3) Measure 1 The revisions to M1 includes language that calls for
evidence related to implementation to be that which demonstrates the entity
performed the action "as called for in the GMD Plan...".While ERCOT understands the
value of linking implementation evidence to the plan, the way it is drafted it could be
interpreted very rigidly such that any operational deviation from the plan would be a
violation. Obviously if you have a plan it should be used, but neither the standard nor
the measure should be so rigid that if the operators cannot deviate from the plan if
necessary based upon unintended circumstances without the risk of noncompliance
with this requirement - entities should be able to take actions outside the four corners
of the plan if necessary, and the standard and compliance measures should clearly
accommodate such actions to avoid unintended consequences where the best
operational actions are not taken because entities do not want to risk noncompliance.4)
Requirement 2 Requirement 2 mandates that the RC share forecasted and current
space weather information in accordance with its plan. As an initial matter, this
implicitly requires RCs to have forecasted and current space weather information in our
plans even though the substantive requirements related to the plan in R1 don't require
that. This creates ambiguity in terms of whether that is a substantive obligation for the
plan. For example, can an RC not have this in their plan, and, if so, does that make that
requirement inapplicable in an audit? Another potential ambiguity related to this
requirement is that there is no direction in terms of the entities the RC is required to
disseminate this information to under the requirement. ERCOT understands the
standard leaves this to the RC plan, but again, does that mean the RC does not have to
have this in its plan? If this obligation is retained, the scope should be aligned with the
functional entities in the standard that have GMD procedural roles (currently just TOPs
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
- although as noted ERCOT questions whether GOPs need to be included in the
standard). Also, if this is going to be a plan requirement that should be explicit. To
make it clear, it should be established as a substantive component of the plan as part of
R1. However, ERCOT does not support this as a substantive requirement. The standard
should dictate the substance of functional entity plans.ERCOT also questions the need
for the RC to disseminate that information. The information can be obtained by other
functional entities independent of RC dissemination, and that obligation, if the SDT
elects to require entities to obtain this information, should be assigned to those
entities. As drafted, this unnecessarily creates an opportunity for RC non-compliance
with what is really administrative obligation i.e. distributing information that can be
obtained independent of the RC. To the extent there is an inconsistency risk in terms of
the sources/substance of this information, that risk could be managed by the RC
coordination role.In addition to the above issues, the requirement is otherwise vague
and ambiguous in terms of the scope of the information disseminated. For example,
what is the timing for the dissemination? Again, the draft language leaves this to the
RC plan, but as discussed, it is not clear if the RC has to have anything related to this,
and if it does not, what the impact of that would be in an audit. If this implicitly
requires the RC to have this process in its plan, the issue is what is the scope for all
aspects - e.g. audience, timing, etc.? Granted the way it is drafted the RC has complete
discretion, but there is a concern whether that discretion will be respected by the ERO
in the exercise of its CMEP function.To mitigate the potential issues with this
requirement, ERCOT believes it should be removed because the standard should
require a plan, but should not dictate the substantive components of the plan.
Alternatively the standard should be revised to make the obligations explicit and clear
with respect to what is required - e.g. R 3.1 makes it clear that TOPs are required to
have a process to obtain space weather information.5) Requirement 3 Related to the
above comments on R2, R3 requires TOPs to get space weather info. Given this
independent obligation, why does the RC have an obligation to disseminate that info?
As discussed, it is unnecessary and creates unnecessary compliance risk.6)
Requirements 3.2 and 3.3 As drafted, these requirements seem too prescriptive. While
it is reasonable that a plan establishes actions relative to specific conditions. However,
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
the language should be clear that these are recommended actions, but are illustrative
and non-exclusive. Functional entities should have the flexibility necessary to take
actions outside of the plan if operating conditions change and counsel for operating
actions outside of the four corners of the plan.7) Measure 3 Similar to the above
comment on Measure 1, as drafted, Measure 3 could be interpreted in a manner that is
too prescriptive and limiting, which could create the risk of undermining effective
operations by limiting operator actions to the four corners of the plan or risk
noncompliance risk. This would undermine the operational flexibility necessary to act
outside of the plan if system conditions warranted such actions without risking violation
of the requirement.
SERC OC Review
Group
Yes
In R1 the requirement calls for the RC to review an “Operating Procedure”. We request
the SDT to consider adding “Operating Process” so it is consistent with R3.
Duke Energy
Yes
In R1.2, the requirement calls for the RC to review an “Operating Procedure”. Duke
Energy recommends adding “Operating Procedure or Operating Process”for
consistency with R3.
US Bureau of
Reclamation
Yes
The Bureau of Reclamation (Reclamation) appreciates the drafting team’s decision to
require Reliability Coordinators (RCs) to disseminate space weather information rather
than requiring each TOP to acquire and disseminate space information.
Northeast Power
Coordinating Council
Yes
The Time Horizon brackets for Requirement R1 incorporate four (4) Time Horizons
shown as: [Time Horizon: Long-term Planning, Operations Planning, Same-day
Operations, Real-time Operations]It is not clear which Time Horizon goes with what
part of Requirement R1. Suggest adding the clarification in a Rationale Box as
follows:Development of the GMD Operating Plan is in the Long-Term Planning Time
Horizon. Maintenance of the GMD Operating Plan is in the Operations Planning Time
Horizon. Implementation of the GMD Operating Plan is in the Same-Day and Real-Time
Time Horizons.
Consideration of Comments
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Organization
Yes or No
Question 1 Comment
ISO/RTO Council
Standards Review
Committee
Yes
We agree with most of the proposed changes, and commend the SDT for responding
positively to industry comments especially those that propose removal of the P.81 type
of requirements, and the apparent redundancy/overlap with IRO-005-3.1a, R3.
Nevertheless, we offer the following comments intended to further improve the
standard.1. Certain wording in the proposed R2 introduces an unclear requirement in
R2 and implied requirements in R1. R2 stipulates that the RC shall dissemintate
forecasted and current space weather information “as specified in the Reliability
Coordinator's GMD Operating Plan”. It is not clear what is it in the GMD Operating Plan
that the RC must follow: is it the entities to whom the RC need to disseminate the
information, or is it the forecast and current space weather information, or is it the
timing for the dissemination, or a combination or all of the above? R1 does not provide
this detail.We suggest the SDT to either add the detail in R1, or to remove or reword
the phrase “as specified in the Reliability Coordinator’s GMD Operating Plan” to remove
the uncertainty and implied requirement.2. We would also suggest some wording
change to R1, which currently stipulates that:R1. Each Reliability Coordinator shall
develop, maintain, and implement a GMD Operating Plan that coordinates GMD
Operating Procedures within its Reliability Coordinator Area.A plan does not
“coordinate”. Depending on the intent of the requirement - whether it mandates the
RC to coordinate the GMD operating procedure or the RC to have a GMD operating
plan that contains the coordinated operating procedures, and to more specifically
indicate who to coordinate with, a more appropriate wording could be:”Each Reliability
Coordinator shall develop, maintain, and implement a GMD Operating Plan to
coordinate GMD Operating Procedures of the Transmission Operators within its
Reliability Coordinator Area.”Or, the wording could be:”Each Reliability Coordinator
shall develop, maintain, and implement a GMD Operating Plan that reflects (or covers
or stipulates) the coordinated GMD Operating Procedures of the Transmission
Operators within its Reliability Coordinator Area.”
Xcel Energy
Yes
We have the following additional comments, but don’t view them as show
stoppers.Because R2 specifies that the RC must disseminate space weather information
Consideration of Comments
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28
Organization
Yes or No
Question 1 Comment
as specified it he RC GMD Op Plan, it would seem logical that there be a sub
requirement in R1 that requires the RC has a process to distribute the space weather
and list the entities and/or functions for distribution.R3.1 seems unnecessary since R2
requires the RC to disseminate space weather info, presumably the TOPs are included.
It isn’t clear what steps or tasks an entity would have to ‘receive’ space weather
information.
NERC Compliance
Policy
Yes
Bonneville Power
Administration
Yes
Arizona Public Service
Co.
Yes
PacifiCorp
Yes
Manitoba Hydro
Yes
Public Utility District
No.1 of Snohomish
County
Yes
Idaho Power
Yes
Tri-State Generation
and Transmission
Association, Inc.
Yes
Oncor Electric
Yes
Consideration of Comments
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29
Organization
Yes or No
Question 1 Comment
Delivery Company LLC
NV Energy
Yes
Seminole Electric Cooperative, Inc.
Seminole asks the SDT to add language to the Standard that indicates that Industry and
NERC intend to allow for consideration of system topology, including geographical
orientation, in developing a GMD Operating Plan. Seminole is aware that this is the
intent of the SDT and therefore Seminole proposes the following language, or similar
language, be added in each Requirement requiring an Entity to develop a type of GMD
Operating Plan and/or set of Operating Procedures:”An Entity can take into
consideration such entity-specific factors such as geography, geology, and system
topology in developing a GMD Operating Plan/set of Operating Procedures.”Seminole
acknowledges that the SDT did not adopt this suggestion during the last comment
period for the reason that the SDT did not wish to begin naming criteria that could be
utilized in documenting an Operating Plan, i.e., an exhaustive list. However, while
reviewing the SDT’s Network Applicability document posted with this Standard, NERC
incorporated two out of the three Network Definition Considerations into the Proposed
Standard, those two being the wye-grounded power transformer requirement and the
lower limit voltage of 200 kV, while not adopting the system topology consideration.
Seminole agrees with NERC that this is an important consideration in assessing GMD
impacts and believes that this should be incorporated into the Standard in a manner
that does not restrict additional considerations. As previously noted, the above
suggested language comes directly from the SAR for this project.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
30
2. Do you agree that the VRFs and VSLs support the reliability objectives of the standard and meet FERC and NERC guidelines? If you
do not agree or you agree in general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on the VRFs and VSLs. The Standard Drafting Team applied the
NERC criteria and FERC Guidelines when proposing VRFs and VSLs for EOP-010-1. A justification has been posted to the project page
(http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx).
Organization
Yes or No
Question 2 Comment
ACES Standards
Collaborators
No
Because we question the need for the standard at this juncture, we cannot support the
VSLs or VRFs. At best, the VRFs should all be low. For a requirement to be assigned a
Medium VRF, a single violation of the requirement would have to “directly affect the
electrical state or the capability of the bulk electric systems, or the ability to effectively
monitor and control the bulk electric system” as defined in the Medium VRF definition.
A single violation of any of these requirements will not “directly affect the electrical state
or the capability of the bulk electric systems, or the ability to effectively monitor and
control the bulk electric system.” Other standards would have to be violated first. For
example, both TOP-002-2.1b R8 and TOP-004-2 R6.1 would have to be violated as well to
effect the electrical state, monitoring and control of the bulk electric system. TOP-0022.1b R8 requires the TOP to plan to meet voltage and/or reactive limits, including the
deliverability/capability for any single contingency. TOP-004-2 R6.1 requires the TOP to
have policies and procedures for monitoring and controlling voltage levels and reactive
power flows. Other requirements that would have to be violated include EOP-001-2 R2.2
and IRO-014-1 R1.
American Electric
Power
No
We do not believe failure to meet R3.3, i.e. failure to terminate the Operating Procedure
or Process after a GMD event, justifies a Medium VRF. Instead, a “Low” VRF is
Organization
Yes or No
Question 2 Comment
recommended.
Flathead Electric
Cooperative, Inc.
No
CPS Energy
No
Centerpoint Energy
No
CenterPoint Energy does not believe the lack of a documented procedure should
produce a High VRF or Severe VSL.
Public Utility District
No.1 of Snohomish
County
Yes
Because GMD can be a wide area event the TOP efforts should focus on coordinating
operations and procedures with the RC. Also, GMD is a high-impact, low-frequency
event so overall risk to the TOP should be assessed to make certain the operations and
procedures are commensurate with the risk to reliable operation of the Bulk Electric
System.
SPP Standards Review
Group
Yes
We would prefer to see the VRFs at Low rather than the assigned Medium, but can live
with them as proposed.
Northeast Power
Coordinating Council
Yes
SERC OC Review Group
Yes
Duke Energy
Yes
ISO/RTO Council
Standards Review
Committee
Yes
Bonneville Power
Administration
Yes
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
32
Organization
Yes or No
Arizona Public Service
Co.
Yes
PacifiCorp
Yes
Colorado Springs
Utilities
Yes
US Bureau of
Reclamation
Yes
Foundation for
Resilient Societies
Yes
Manitoba Hydro
Yes
Hydro One
Yes
Idaho Power
Yes
Independent Electricity
System Operator
Yes
Electric Reliability of
Texas, Inc.
Yes
Tri-State Generation
and Transmission
Association, Inc.
Yes
Oncor Electric Delivery
Yes
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
Question 2 Comment
33
Organization
Yes or No
Question 2 Comment
Company LLC
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
34
3. The Implementation Plan provides conditions for determining when the Requirements in EOP-010-1 become effective in each
jurisdiction. Do you agree with the Implementation Plan as written? If you do not agree or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The drafting team thanks all who commented on the Implementation Plan. Some stakeholders also
commented that the six-month implementation period was too short. The drafting team believes that the requirements of the proposed
standard can be met within that period. One commenter expressed concern that the stage 2 standards could affect the implementation
or applicable entities of EOP-010-1. The drafting team believes the scope and purpose of the two stages in Project 2013-03 are properly
established and separate as described in the Standard Authorization Request.
Organization
Yes or No
Question 3 Comment
CPS Energy
No
Implementation should be at the regional level
Arizona Public Service Co.
No
The implementation period should be no less than 1 year, 6 months implementation
time would cause significant strain and will not allow an effective procedure to be
developed.
Oncor Electric Delivery
Company LLC
No
The Implementation Plan timeline calls for implementation 6 months from the
standard approval or on the first day following the retirement of IRO-005-3.1a. This
timeline does not provide sufficient time to create the necessary procedures or
processes and train necessary personnel to those processes and procedures. The
preferable timeline would be for implementation 12 months from the standard
approval or on the first day following the retirement of IRO-005-3.1a, whichever is
later.
Flathead Electric
Cooperative, Inc.
No
Xcel Energy
Yes
none
Consideration of Comments
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35
Organization
Yes or No
Question 3 Comment
Public Utility District No.1
of Snohomish County
Yes
Public Utility District No.1 of Snohomish County agrees in general, however
appropriate implementation time should be given so that the Reliability Coordinator
(“RC”) has the time to develop the GMD operating plan and coordinate with
neighboring RCs as well as other impacted functions.
US Bureau of Reclamation
Yes
Reclamation appreciates the drafting team’s efforts to avoid a situation where both
IRO-005-3.1a Requirement R3 and EOP-010 Requirement R2 are effective at the same
time.
SPP Standards Review
Group
Yes
The treatment of the Effective Date in the standard appears to address the issue of
implementation in the Canadian provinces. Hopefully this will resolve the issue.
ACES Standards
Collaborators
Yes
While we continue to believe there is another equally efficient and more efficient
alternative to development of this standard, the implementation plan is reasonable
within the constraints of this standard. However, we have concerns that the second
phase of this project may alter the work done in phase one, including modifications to
the implementation plan and the entities that could be subject to compliance with this
standard.
Northeast Power
Coordinating Council
Yes
NERC Compliance Policy
Yes
SERC OC Review Group
Yes
Duke Energy
Yes
ISO/RTO Council
Standards Review
Committee
Yes
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
36
Organization
Yes or No
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Colorado Springs Utilities
Yes
Foundation for Resilient
Societies
Yes
Manitoba Hydro
Yes
Hydro One
Yes
Idaho Power
Yes
Independent Electricity
System Operator
Yes
Electric Reliability of
Texas, Inc.
Yes
Tri-State Generation and
Transmission Association,
Inc.
Yes
NV Energy
Yes
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
Question 3 Comment
37
4. If you have any other comments for the drafting team to consider that you haven’t already mentioned, please provide them here:
Summary Consideration: The drafting team thanks all who responded. The drafting team adopted a number of suggestions for clarifying
the standard. A small number of commenters suggested substantive changes such as adding Requirements or language, but the drafting
team does not believe there is a consensus to make substantive changes to the standard at this time. A summary of comments and the
drafting team's response is provided below:
•
•
•
•
•
Predetermined conditions required for GMD Operating Procedures or Operating Processes. A commenter suggested the
qualifier "if known" be added to Requirement R3 part 3.2 so entities without a study or GIC measuring equipment would not
be required to include predetermine conditions for operator actions in the GMD Operating Procedure or Operating Process.
The drafting team believes that the requirement as written provides the flexibility to use good professional judgment to develop
effective GMD Operating Procedures and Operating Processes.
Tailoring of operating procedures. A commenter requested that language be included in Requirement R3 to reflect that
entities are allowed to consider various entity-specific factors in developing GMD Operating Processes or Operating
Procedures. The drafting team agrees with the principle that an entity can consider entity-specific factors in developing its
process and procedure and has provided for this in the standard. The following has been added to the rationale box to describe
the drafting team's intent: "In developing an Operating Procedure or Operating Process, an entity may consider entity-specific
factors such as geography, geology, and system topology."
Transmission Operator responsibility to receive space weather information. A commenter stated that Requirement R3 part
3.1 should be removed since Requirement R2 placed responsibility for providing this information on the RC. The drafting team
believes that receiving space weather information is an essential component to GMD Operating Procedures or Operating
Processes. EOP-010-1 recognizes that Transmission Operators may use several sources in addition to the Reliability
Coordinator's disseminated forecast information to obtain more detailed local or system-specific information.
Requirement to ensure coordination between Reliability Coordinators. A commenter recommended a requirement be
included added to require adjacent Reliability Coordinators to share their respected GMD Operating Plans. The SDT believes
coordination between and among Reliability Coordinators is adequately addressed in existing IRO standards. (Refer to IRO-014,
Requirement R1).
A commenter recommended revising the SAR to include the term Operating Processes as currently used in the standard. The
SAR, as accepted by the Standards Committee, adequately defines the project scope without the recommended change.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
38
•
•
•
•
A commenter suggested alternate wording for Requirement R3 part 3.3 (terminating the GMD Operating Procedure or
Operating Process). The drafting team considered the suggested alternate wording and determined that the suggested change
did not provide additional clarity.
A commenter identified a correction needed in the Functional Entity Applicability whitepaper that the drafting team has
incorporated. The revised Functional Entity Applicability whitepaper (clean, and redline showing the changes made) has been
posted on the project page (.http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx)
A commenter recommended a change to Requirement R3 to indicate that the GMD Operating Procedures or Operating
Processes were intended to mitigate the effects of GMD events. The drafting team considered the proposed language and
determined that the suggested change did not provide additional clarity.
A commenter reiterated that system studies should be performed before operating procedures should be required. The
drafting team believes that the standard as written provides the flexibility to use good professional judgment to develop
effective GMD Operating Procedures and Operating Processes.
Organization
Yes or No
ISO/RTO Council Standards
Review Committee
No
Manitoba Hydro
No
Hydro One
No
Flathead Electric
Cooperative, Inc.
No
Idaho Power
No
Oncor Electric Delivery
Company LLC
No
CPS Energy
No
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
Question 4 Comment
39
Organization
Yes or No
Question 4 Comment
Arizona Public Service Co.
Yes
Suggest changing R3.2 to as follows:System Operator actions to be initiated based on
predetermined conditions, if known to be a susceptible to GMD. During the Webinar, it
was pointed out that TOP is not required to have a study or measurement to find the
predetermined conditions and most TOP would not know of such conditions existing in
their system. The suggested language change would make it clear that they are not
required to know the predetermined conditions.
ACES Standards
Collaborators
Yes
(1) Requirement R2 should be made a sub-part of Requirement R1 to avoid double
jeopardy and because it is essentially a constraint on the Operating Plan. If a registered
entity fails to write an Operating Plan, it will also fail to include in its Operating Plan the
method for disseminating space weather. Since violations are assessed per
requirement, one compliance failure could result in two compliance violations of R2 and
R3. Thus, if R2 is written as a sub-part of R1, failure develop an Operating Plan will be
assessed as a single violation of the combined requirement. Furthermore, R2 essentially
is a requirement for what should be contained in the Operating Plan and, therefore,
more appropriately belongs as a sub-part of R1. (2) Part 3.1 in R3 is unnecessary and
redundant with other requirements. R2 already compels the RC to disseminate space
weather information. Because the RC is a higher authority than the TOP, the TOP is
already required to receive the information as a result by implication. The RC’s
authority is documented in IRO-001-1a R3 and R8. The RC may issue directives to the
TOP to follow its GMD Operating Procedure or Process while disseminating information
about severe space weather. Furthermore, NERC already designates MISO and WECC
RC to monitor the space weather through the National Oceanic and Atmospheric
Administration (NOAA) Space Weather Prediction Center (SWPC). MISO communicates
this information to the Eastern and ERCOT Interconnections through reliability
coordinator information system (RCIS) and WECC communicates it to the Western
Interconnection as documented in a NERC alert. Codifying a process that is already in
place and works effectively only perpetuates the existing compliance model that places
too much emphasis on documentation and not enough on reliability. (3) The SAR
should be modified to indicate that Stage 1 will require registered entities to develop
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
40
Organization
Yes or No
Question 4 Comment
and implement Operating Processes and Operating Plans in addition to Operating
Procedures. The SAR only references the development and implementation of
Operating Procedures which is not consistent with the standard that includes Operating
Plans and Operating Processes. (4) We believe the literal meaning of the language in R3
Part 3.3 is not what is intended by the drafting team. As written, the language could be
read to literally mean that the Operating Process or Operating Procedure must include
language for retiring the Operating Process or Procedure. The problem is with the use
of “terminate the Operating Procedure or Operating Process.” Terminate means to
come to an end. Thus, terminating the Operating Procedure or Operating Process which
are documents means to end the document. Obviously, the purpose is to terminate the
use of the Operating Procedure or Operating Process when the GMD event has ended.
We suggest using the language from the SAR for R3 Part 3.3 as it is clearer and has a
more exact meaning of what is intended. The language in the SAR is: “Criteria for
discontinuing the use of Operating Procedures at the conclusion of a GMD event.” (5)
The Long-term Planning Time Horizon for R1 and R3 should be removed. The functional
entities to which the standard applies are not planning entities per the functional model
and have no long-term planning responsibilities. The Long-Term Planning Horizon
covers a period of one year or longer. An operating procedure or plan will cover the
Real-Time Operations horizon or Operations Planning horizon at best. By NERC Glossary
definition, an operating plan, process or procedure will not cover the Long-Term
Planning horizon. An operating procedure lists the specific steps that should be taken
by specific operating positions. An operating process includes steps that may be
selected based on “Real-time conditions.” An operating plan contains operating
procedures and processes which are applied in real-time operations. (6) We are
concerned that implementation of an operating procedure for GMD may require the
removal a number of transformers and could be viewed as causing a burden to
neighboring systems contrary to TOP-001-1a R7. TOP-001-1a R7 compels the TOP and
GOP to not remove facilities from service if it would burden neighboring systems unless
there is not time for notification and coordination. Could the requirement to write an
operating procedure for responding to GMD events be viewed as allowing time for
coordination and notification particularly if the TOP documented in their plan to notify
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
41
Organization
Yes or No
Question 4 Comment
their RC? If EOP-010 persists, TOP R7.3 should be modified to clarify that a TOP and
GOP may not have sufficient time during an extreme GMD event to make appropriate
notifications and the requirement for the RC to have an operating plan will satisfy this
required coordination. (7) The white paper supporting functional entity applicability
should be modified. On page three, the last sentence just before the “Justification for
Omitting Functional Entities” section is inconsistent with the standard. It states that
“some procedures can be put in place by all TOPs.” The standard limits the procedures
to only TOPs with a transformer with a high-side wye-grounded winding greater than
200 kV. Please modify the sentence in the whitepaper for consistency with the
standard. (8) We do not believe the science of how GMDs impact the electric grid is
settled. This is evidenced by multiple reports with significantly varying conclusions.
While the FERC order indicated that most reports agree that there is a minimum risk for
voltage collapse due to excessive reactive power consumption of transformers during
extreme GMD events, the reports may not emphasize the geographic risk of the
problem. For example, does a utility in South Florida have the same risk as a utility in
northern Maine? If the risks are different, a requirement for an operating procedure for
all entities including the southernmost entities is premature at this point. We
understand that NERC has an obligation to respond to the FERC GMD directive and will
support them in their efforts, however, we wonder if NERC should look for an equally
efficient and effective alternative. We believe that such an alternative should include
pointing to the existing and proposed standards requirements that require registered
entities to respond to voltage emergencies as documented in our responses to other
questions.(9) Thank you for the opportunity to comment.
Colorado Springs Utilities
Yes
1. Thank you for all of your work SDT! 2. For the record. We have concern over the fact
that action is being required prior to defining the risk? A blind shotgun approach
consumes a lot of unnecessary resources, as it is anticipated that there are many
entities that will not be at risk to GMDs. We understand that FERC is pushing for action,
but think that their push should be founded on established risk.
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
42
Organization
Yes or No
Question 4 Comment
Florida Municipal Power
Agency
Yes
According to the ORNL 319 report
(http://web.ornl.gov/sci/ees/etsd/pes/pubs/ferc_Meta-R-319.pdf, Figure 1-17), 3 phase
/ 3 leg core design transformers are much less likely to saturate and result in MVAR
demands about 25% of that of three single phase transformers. Hence, the applicability
for > 200 kV and < 400 kV (i.e., the 230 and 345 kV transformers) ought to be limited to
single phase transformers connected in a grounded wye configuration. This is the
primary reason for FMPA's negative vote.FMPA also believes that the 200 kV threshold
ought to be raised to 300 kV. The resistance of 230 kV lines is significantly higher than
345 kV lines, which will significantly reduce GIC (see Figure 1-12 noting that the chart is
semi-logarithmic) for lines of similar length (see figure 1-14). This is largely due to the
fact that most 345 kV lines are two conductor bundles for RFI purposes and most 230 kV
lines are single conductor; hence, 230 kV lines are roughly twice the resistance of 345 kV
lines for the same length of line. Although FMPA believes the threshold should be raised
to 300 kV, we can "live" with a 200 kV threshold if the applicability to 200 kV is to TOPs
that operate three single leg core design transformers connected in a grounded wye
configuration.
Bonneville Power
Administration
Yes
BPA recommends the drafting team change the language of the first sentence of R3,
from “Each Transmission Operator shall...or Operating Process to mitigate the effects of
GMD events on the reliable operation of its respective system.” To “Each Transmission
Operator shall...or Operating Process intended to mitigate the effects of GMD events on
the reliable operation of its respective system.”
Duke Energy
Yes
Duke Energy would like to thank the SDT for their response to stakeholder comments.
Foundation for Resilient
Societies
Yes
For further background information on the Foundation's support of wider jurisdiction
for coordinated "operating procedures" see our March 2013 case study of Maine and
ISO-New England in a solar geomagnetic storm, found at www.resilientsocieties.org and
the Foundation's comments responsive to queries by the Maine Public Utilities
Commission, in MPUC Docket 2013-00415 (Oct 4, 2013), and our Supplemental and
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
43
Organization
Yes or No
Question 4 Comment
Reply Comments in that same Docket (October 15, 2013).
Nebraska Public Power
District
Yes
NPPD supports the comments submitted by the Southwest Power Pool. In addition we
would like to add this comment:”The drafting team is requiring operating procedures to
be in place prior to studying the GMD effects on the TOP system. To determine what
effects the GMD will have on the TOP’s system, the studies should be preform first and
then the operating procedures developed. The drafting team is requiring generic
operating procedures which may or may not address the GMD issues on the TOP’s
system. It makes more sense to delay the implementation of the operating procedures
until the studies have been performed.”
ReliabilityFirst
Yes
ReliabilityFirst votes in the affirmative because this standard will help to mitigate the
effects of geomagnetic disturbance (GMD) events by requiring the Reliability
Coordinator to implement Operating Procedures and the Balancing Authorities and
Transmission Operators to implement Operating Plans. ReliabilityFirst offers the
following comments for consideration:1. Requirement R1 - To be consistent with the
language in Requirement R3, ReliabilityFirst believes the term “Operating Process”
should be added to Requirement R1. Furthermore, Requirement R1 should include a
statement tying it back to the Transmission Operator’s Operating Procedure or
Operating Process in Requirement R3. ReliabilityFirst recommends the following for
consideration: “Each Reliability Coordinator shall develop, maintain, and implement a
GMD Operating Plan that coordinates GMD Operating Procedures [and Operating
Processes, as developed in Requirement R3,] within its Reliability Coordinator Area. At a
minimum, the GMD Operating Plan shall include:...”2. Consideration for new
Requirement R4 - ReliabilityFirst submitted this comment during the last comment
period but believes it may have been overlooked (i.e., we believe it was not addressed
in the consideration of comments report). ReliabilityFirst recommends including a new
Requirement R4 which would require adjacent Reliability Coordinators to share their
respected GMD Operating Plans. During a GMD event, it can span multiple Reliability
Coordinator areas and ReliabilityFirst believes the adjacent Reliability Coordinators
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
44
Organization
Yes or No
Question 4 Comment
should be aware of each other’s GMD Operating Plans.
Oklahoma Gas & Electric
Yes
The Standard, as written, requires entities to have a plan, but it fails to identify a clear
and measurable expected outcome, such as a stated level of reliability performance, a
reduction in a specified reliability risk (prevention), or a necessary competency.
Northeast Power
Coordinating Council
Yes
The text of the "Effective Dates" section should be consistent with the EOP family of
standards to reduce the variance between EOP Standards.Regarding Requirement R1
and its Measure M1, times for completion need to be added. The Violation Severity
Levels have to be revised accordingly.The contents of the Rationale Boxes for R1 and R3
as they shown are obvious, and can be removed. In the response to Question 1 above
we suggested an addition to the Rationale Box for R1. The Rationale Box for R2 should
not repeat wording from R2.
American Electric Power
Yes
The time horizon “Long-term Planning” seems more appropriate for the Stage 2 aspect
of this GMD standard, and not for the Stage 1. Please provide carification for how Longterm Planning is to be applied for R1 and R3 as well as justification for doing so.Although
this may be ouside the scope of this project team, we encourage NERC to resolve the
discrepancies between the definition of Long-term Planning as provided in NERC’s Time
Horizon and the definition of “Long-Term Transmission Planning Horizon” in the NERC
Glossary of Terms.AEP recognizes the perceived urgency of this project, supports the
objective of the proposed standard, and appreciates the efforts of the drafting team.
Our negative vote is driven solely by our desire for additional clarity as stated in our
comments. AEP foresees voting in the affirmative once the issues and concerns
expressed in this response are addressed in future versions of the draft.
Tri-State Generation and
Transmission Association,
Inc.
Yes
Tri-State is still concerned with the Standard Drafting Team’s decision setting the limit of
applicable transformers from >200kV versus >300kV. This critical decision will have
significant cost and time ramifications on the industry. The workload for Tri-State will
increase nearly five-fold based on the amount of transformers that fall into the 200300kV range. We appreciate the work that the volunteer task force has accomplished in
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
45
Organization
Yes or No
Question 4 Comment
helping to prepare the NERC “Network Applicability” paper, but Tri-State believes such a
critical decision in setting the limit should be based on more extensive knowledge. The
“Network Applicability” justification for including 200kV circuits is only based on an
analysis of a small simulated network consisting of two 500/230kV autotransformers
with only a few lines running into and out of that station. That analysis, summarized in
Table A1 (pg. 7), predicts a decrease of GIC from 5.5 to 2.8 Amps if the 230kV elements
are included. The study also estimates an increase in var absorption from 12.5 to 14
Mvar if the 230kV elements are included. Tri-State suggests that these slight variances
are well within the error range in the overall assumptions for the many parameters used
to predict GIC itself. Parameters such as the line induced kV/km, the magnitude and
duration of solar events, the deep earth soils geology, accuracy of the transformer
models, ground grid resistance (which may vary season to season), etc. Our suggestion
is to give the NERC task force increased time to do research and in the meantime adopt
a criteria of detailed analysis of >300kV with a 10% safety factor added for the possible
<300kV impact.
SPP Standards Review
Group
Yes
PacifiCorp
Yes
We want to thank the drafting team for taking the time to provide summary responses
to help the industry’s understanding of the changes even though they didn’t have to.
Public Utility District No.1 of Snohomish County
Although GMD and Geomagnetically Induced Currents (“GIC”) have been well
understood for many decades, how they impact various elements of the power grid are
still being assessed by the electric industry and equipment manufacturers. Significant
discussion has taken place on this subject in many different forums; however there is
very little credible analysis on the level of impact a GMD can have on the BES and what
level of risk a GMD poses compared to other adverse impact events.
SERC OC Review Group
We would like to thank the SDT for their responses to stakeholder comments.The
comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Review Group only and should not be construed as the
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
46
Organization
Yes or No
Question 4 Comment
position of the SERC Reliability Corporation, or its board or its officers.
END OF REPORT
Consideration of Comments
Project 2013-03 Geomagnetic Disturbance Mitigation | October 2013
47
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Draft 3
Stage 1 Standard
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee accepted the Standard Authorization Request (SAR) submitted by
the Geomagnetic Disturbance Task Force (GMD TF) and approved Project 2013-03
(Geomagnetic Disturbance Mitigation) on June 5, 2013.
2. The draft standard was posted for a 45-day formal comment period and initial ballot from
June 26, 2013 through August 12, 2013. The SAR was posted for informal comment during
the same period.
3. The second draft of the standard was posted for a 45-day formal comment period and
additional ballot from September 4, 2013 through October 18, 2013.
Description of Current Draft
This is the third posting of the proposed standard. It is posted for a 10-day final ballot.
Anticipated Actions
Anticipated Date
Final ballot
October 2013
BOT adoption
November 2013
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Effective Dates
The first day of the first calendar quarter that is six months after the date that this standard is
approved by an applicable governmental authority or as otherwise provided for in a jurisdiction
where approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the standard
shall become effective on the first day of the first calendar quarter that is six months after the
date this standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Version History
Version
1
Date
TBD
Action
Project 2013-03
Change
Tracking
N/A
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Plans, Processes, and Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes a
power transformer with a high side wye-grounded winding with terminal
voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to adversely impact the
reliable operation of interconnected transmission systems. 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
Protection System Misoperation, the combination of which may result in voltage
collapse and blackout.
B. Requirements and Measures
R1. Each Reliability Coordinator shall develop,
maintain, and implement a GMD Operating
Plan that coordinates GMD Operating
Procedures or Operating Processes within its
Reliability Coordinator Area. At a minimum,
the GMD Operating Plan shall include:
[Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning, Operations
Planning, Same-day Operations, Real-time
Operations]
1.1 A description of activities designed to
mitigate the effects of GMD events on
the reliable operation of the
interconnected transmission system
within the Reliability Coordinator Area.
1.2 A process for the Reliability Coordinator
to review the GMD Operating
Procedures or Operating Processes of
Transmission Operators within its
Reliability Coordinator Area.
Dra ft 3: Oc to b e r 25, 2013
Rationale and supporting information
for Requirement R1: An Operating Plan
is implemented by carrying out its stated
actions.
Coordination is intended to ensure that
Operating Procedures are not in conflict
with one another.
An Operating Plan is maintained when it is
kept relevant by taking into consideration
system configuration, conditions, or
operating experience, as needed to
accomplish its purpose.
Elements of Requirement R1 take place in
various time horizons. Development of the
GMD Operating Plan occurs in the LongTerm Planning Time Horizon.
Maintenance of the GMD Operating Plan
occurs in the Operations Planning Time
Horizon. Implementation of the GMD
Operating Plan occurs in the Operations
Planning, Same-Day and Real-Time Time
Horizons.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
M1. Each Reliability Coordinator shall have a current GMD Operating Plan meeting all the
provisions of Requirement R1; evidence such as a review or revision history to
indicate that the GMD Operating Plan has been maintained; and evidence to show that
the plan was implemented as called for in its GMD Operating Plan, such as dated
operator logs, voice recordings, or voice transcripts.
R2. Each Reliability Coordinator shall disseminate
forecasted and current space weather
information to functional entities identified as
recipients in the Reliability Coordinator's GMD
Operating Plan. [Violation Risk Factor:
Medium] [Time Horizon: Same-day
Operations, Real-time Operations]
M2. Each Reliability Coordinator shall have
evidence such as dated operator logs, voice
recordings, transcripts, or electronic
communications to indicate that forecasted and
current space weather information was
disseminated as stated in its GMD Operating
Plan.
R3. Each Transmission Operator shall develop,
maintain, and implement a GMD Operating
Procedure or Operating Process to mitigate the
effects of GMD events on the reliable
operation of its respective system. At a
minimum, the Operating Procedure or
Operating Process shall include: [Violation
Risk Factor: Medium] [Time Horizon: Longterm Planning, Operations Planning, Same-day
Operations, Real-Time Operations]
3.1. Steps or tasks to receive space weather
information.
3.2. System Operator actions to be initiated
based on predetermined conditions.
3.3. The conditions for terminating the
Operating Procedure or Operating
Process.
Rationale and supporting information
for Requirement R2: Requirement R2
replaces IRO-005-3.1a, Requirement R3.
IRO-005-4 has been adopted by the NERC
Board and filed with FERC, and will retire
IRO-005-3.1a Requirement R3. If EOP010-1 becomes effective prior to the
retirement of IRO-005-3.1a, Requirement
R2 shall become effective on the first day
following retirement of IRO-005-3.1a.
Space weather forecast information can be
used for situational awareness and safe
posturing of the system. Current space
weather information can be used for
monitoring progress of a GMD event.
The Reliability Coordinator is responsible
for disseminating space weather
information to ensure coordination and
consistent awareness in its Reliability
Coordinator Area.
Rationale and supporting information
for Requirement R3: In developing an
Operating Procedure or Operating Process,
an entity may consider entity-specific
factors such as geography, geology, and
system topology.
An Operating Procedure or Operating
Process is maintained when it is kept
relevant by taking into consideration
system configuration, conditions, or
operating experience, as needed to
accomplish its purpose.
M3. Each Transmission Operator shall have a GMD Operating Procedure or Operating
Process meeting all the provisions of Requirement R3; evidence such as a review or
revision history to indicate that the GMD Operating Procedure or Operating Process
has been maintained; and evidence to show that the Operating Procedure or Operating
Process was implemented as called for in its GMD Operating Procedure or Operating
Process, such as dated operator logs, voice recordings, or voice transcripts.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) 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 Reliability Coordinator and Transmission Operator shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity 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 CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning,
Operations
Planning,
Same-day
Operations,
Real-time
Operations
Medium The Reliability
Coordinator had a
GMD Operating Plan,
but failed to maintain
it.
R2
Same-day
Operations,
Real-time
Operations
Medium N/A
R3
Long-term
Planning,
Operations
Planning,
Medium The Transmission
Operator had a GMD
Operating Procedure
or Operating Process,
Dra ft 3: Oc to b e r 25, 2013
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan failed
to include one of the
required elements as
listed in Requirement
R1, parts 1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
N/A
N/A
The Reliability
Coordinator failed to
disseminate forecasted
and current space
weather information to
all functional entities
identified as recipients
in the Reliability
Coordinator's GMD
Operating Plan.
The Transmission
Operator's GMD
Operating Procedure
or Operating Process
The Transmission
Operator's GMD
Operating Procedure or
Operating Process
The Transmission
Operator did not have
a GMD Operating
Procedure or Operating
OR
The Reliability
Coordinator failed to
implement a GMD
Operating Plan within
its Reliability
Coordinator Area.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Same-day
Operations,
Real-time
Operations
Dra ft 3: Oc to b e r 25, 2013
but failed to maintain
it.
failed to include one of
the required elements
as listed in
Requirement R3, parts
3.1 through 3.3.
failed to include two or
more of the required
elements as listed in
Requirement R3, parts
3.1 through 3.3.
Process
OR
The Transmission
Operator failed to
implement its GMD
Operating Procedure or
Operating Process.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
D. Regional Variances
None.
E. Interpretations
None.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee accepted the Standard Authorization Request (SAR) submitted by
the Geomagnetic Disturbance Task Force (GMD TF) and approved Project 2013-03
(Geomagnetic Disturbance Mitigation) on June 5, 2013.
2. The draft standard was posted for a 45-day formal comment period and initial ballot from
June 26, 2013 through August 12, 2013. The SAR was posted for informal comment during
the same period.
3. The second draft of the standard was posted for a 45-day formal comment period and
additional ballot from September 4, 2013 through October 18, 2013.
Description of Current Draft
This is the third posting of the proposed standard. It is posted for a 10-day final ballot.
Anticipated Actions
Anticipated Date
45-day Formal Comment Period with Ballot
September 2013
Final ballot
October 2013
BOT adoption
November 2013
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Effective Dates
The first day of the first calendar quarter that is six months after the date that this standard is
approved by an applicable governmental authority or as otherwise provided for in a jurisdiction
where approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the standard
shall become effective on the first day of the first calendar quarter that is six months after the
date this standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Version History
Version
1
Date
TBD
Action
Project 2013-03
Change
Tracking
N/A
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
A. Introduction
1.
Title: Geomagnetic Disturbance Operations
2.
Number:
3.
Purpose: To mitigate the effects of geomagnetic disturbance (GMD) events by
implementing Operating Plans, Processes, and Procedures.
4.
Applicability:
EOP-010-1
4.1. Functional Entities:
4.1.1
4.1.2
5.
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes a
power transformer with a high side wye-grounded winding with terminal
voltage greater than 200 kV
Background:
Geomagnetic disturbance (GMD) events have the potential to adversely impact the
reliable operation of interconnected transmission systems. 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
Pprotection Ssystem Misoperation, the combination of which may result in voltage
collapse and blackout.
B. Requirements and Measures
R1. Each Reliability Coordinator shall
develop, maintain, and implement a
GMD Operating Plan that coordinates
GMD Operating Procedures or
Operating Processes within its
Reliability Coordinator Area. At a
minimum, the GMD Operating Plan
shall include: [Violation Risk Factor:
Medium] [Time Horizon: Long-term
Planning, Operations Planning, Sameday Operations, Real-time Operations]
Rationale and supporting information for
Requirement R1: An Operating Plan is
implemented by carrying out its stated actions.
Coordination is intended to ensure that
Operating Procedures are not in conflict with
one another.
An Operating Plan is maintained when it is kept
relevant by taking into consideration system
configuration, conditions, or operating
experience, as needed to accomplish its purpose.
1.1 A description of activities
designed to mitigate the effects
of GMD events on the reliable
operation of the interconnected
transmission system within the
Reliability Coordinator Area.
Elements of Requirement R1 take place in
various time horizons. Development of the GMD
Operating Plan occurs in the Long-Term
Planning Time Horizon. Maintenance of the
GMD Operating Plan occurs in the Operations
Planning Time Horizon. Implementation of the
GMD Operating Plan occurs in the Operations
1.2 A process for the Reliability
Planning, Same-Day and Real-Time Time
Coordinator to review the GMD
Horizons.
Operating Procedures or
Operating Processes of Transmission Operators within the its Reliability
Coordinator Area.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
M1. Each Reliability Coordinator shall have a current GMD Operating Plan meeting all the
provisions of Requirement R1; evidence such as a review or revision history to
indicate that the GMD Operating Plan has been maintained; and evidence to show that
the plan was implemented as called for in its GMD Operating Plan, such as dated
operator logs, voice recordings, or voice transcripts.
R2. Each Reliability Coordinator shall
disseminate forecasted and current
space weather information as
specifiedto functional entities identified
as recipients in in the Reliability
Coordinator's GMD Operating Plan.
[Violation Risk Factor: Medium] [Time
Horizon: Same-day Operations, Realtime Operations]
Rationale and supporting information for
Requirement R2: Requirement R2 replaces
IRO-005-3.1a, Requirement R3. IRO-005-4 has
been adopted by the NERC Board and filed with
FERC, and will retire IRO-005-3.1a
Requirement R3. If EOP-010-1 becomes
effective prior to the retirement of IRO-005-3.1a,
Requirement R2 shall become effective on the
first day following retirement of IRO-005-3.1a.
M2. Each Reliability Coordinator shall have
evidence such as dated operator logs,
voice recordings, transcripts, or
electronic communications to indicate
that forecasted and current space
weather information was disseminated
as stated in its GMD Operating Plan.
Space weather forecast information can be used
for situational awareness and safe posturing of
the system. Current space weather information
can be used for monitoring progress of a GMD
event.
R3. Each Transmission Operator shall
develop, maintain, and implement a
GMDn Operating Procedure or
Operating Process to mitigate the
effects of GMD events on the reliable
operation of its respective system. At a
minimum, the Operating Procedure or
Operating Process shall include:
[Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning,
Operations Planning, Same-day
Operations, Real-Time Operations]
3.1. Steps or tasks to receive space
weather information.
The Reliability Coordinator is responsible for
disseminating space weather information to
ensure coordination and consistent awareness in
its Reliability Coordinator Area.
Rationale and supporting information for
Requirement R3:
In developing an Operating Procedure or
Operating Process, an entity may consider
entity-specific factors such as geography,
geology, and system topology.
An Operating Procedure or Operating Process is
maintained when it is kept relevant by taking
into consideration system configuration,
conditions, or operating experience, as needed to
accomplish its purpose.
An Operating Procedure or Operating Process is
implemented by carrying out its stated actions.
3.2. System Operator actions to be
initiated based on predetermined conditions.
3.3. The conditions for terminating the Operating Procedure or Operating Process.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
M3. Each Transmission Operator shall have a GMD Operating Procedure or Operating
Process meeting all the provisions of Requirement R3; evidence such as a review or
revision history to indicate that the GMD Operating Procedure or Operating Process
has been maintained; and evidence to show that the Operating Procedure or Operating
Process was implemented as called for in its GMD Operating Procedure or Operating
Process, such as dated operator logs, voice recordings, or voice transcripts.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) 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 Reliability Coordinator and Transmission Operator shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity 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 CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Dra ft 3: Oc to b e r 25, 2013
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning,
Operations
Planning,
Same-day
Operations,
Real-time
Operations
Medium The Reliability
Coordinator had a
GMD Operating Plan,
but failed to maintain
it.
R2
Same-day
Operations,
Real-time
Operations
Medium N/A
R3
Long-term
Planning,
Operations
Medium The Transmission
Operator had a GMD
Operating Procedure
Dra ft 3: Oc to b e r 25, 2013
Moderate VSL
N/A
High VSL
Severe VSL
The Reliability
Coordinator's GMD
Operating Plan failed
to include one of the
required elements as
listed in Requirement
R1, parts 1.1 or 1.2.
The Reliability
Coordinator did not
have a GMD
Operating Plan
N/A
N/A
The Reliability
Coordinator failed to
disseminate forecasted
and current space
weather information as
specifiedto all
functional entities
identified as recipients
in the Reliability
Coordinator's GMD
Operating Plan.
The Transmission
Operator's GMD
Operating Procedure
The Transmission
The Transmission
Operator's GMD
Operator did not have
Operating Procedure or a GMD Operating
OR
The Reliability
Coordinator failed to
implement a GMD
Operating Plan within
its Reliability
Coordinator Area.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
Planning,
Same-day
Operations,
Real-time
Operations
Dra ft 3: Oc to b e r 25, 2013
or Operating Process,
but failed to maintain
it.
or Operating Process
failed to include one of
the required elements
as listed in
Requirement R3, parts
3.1 through 3.3.
Operating Process
failed to include two or
more of the required
elements as listed in
Requirement R3, parts
3.1 through 3.3.
Procedure or Operating
Process
OR
The Transmission
Operator failed to
implement its GMD
Operating Procedure or
Operating Process.
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EOP -010-1 — Ge o m a gn e tic Dis turb a n c e Op e ra tio n s
D. Regional Variances
None.
E. Interpretations
None.
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
R etirem ents
None
R evisions to Glossary Term s
None
Applicable Entities
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side wye-grounded winding with terminal voltage greater than 200 kV
Conform ing Changes to Other Standards
None
Effective Dates
Requirement R2 of EOP-010-1 replaces Requirement R3 of IRO-005-3.1a. IRO-005-4 has been adopted
by the NERC Board and filed with FERC in Docket Number RM13-15-000, and will retire Requirement
R3 of IRO-005-3.1a:
IRO-005-3.1a, Requirement R3:
R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
EOP-010-1 replaces this requirement with the following:
EOP-010-1, Requirement R2:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information to functional entities identified as recipients in the Reliability Coordinator's
GMD Operating Plan.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Therefore, to ensure responsibility for disseminating space weather information in the Reliability
Coordinator Area is maintained while avoiding duplicative requirements being enforceable at the same
time, EOP-010-1 shall become effective as follows:
In jurisdictions where regulatory approval is required:
•
The first day of the first calendar quarter that is six months after the date that this standard is
approved by an applicable governmental authority or as otherwise provided for in that
jurisdiction.
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
In jurisdictions where regulatory approval is not required:
•
The first day of the first calendar quarter that is six months after the date this standard is
adopted by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan – October 25, 2013
2
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Implementation Plan
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan for EOP-010-1 – Geomagnetic Disturbance Operations
Approvals Required
EOP-010-1 – Geomagnetic Disturbance Operations
Prerequisite Approvals
None
R etirem ents
None
R evisions to Glossary Term s
None
Applicable Entities
Reliability Coordinator
Transmission Operator with a Transmission Operator Area that includes any transformer with a high
side wye-grounded winding with terminal voltage greater than 200 kV
Conform ing Changes to Other Standards
None
Effective Dates
Requirement R2 of EOP-010-1 replaces Requirement R3 of IRO-005-3.1a. IRO-005-4 has been adopted
by the NERC Board and filed with FERC in Docket Number RM13-15-000, and will retire Requirement
R3 of IRO-005-3.1a:
IRO-005-3.1a, Requirement R3:
R3. Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and
assist as needed in the development of any required response plans.
EOP-010-1 replaces this requirement with the following:
EOP-010-1, Requirement R2:
R2. Each Reliability Coordinator shall disseminate forecasted and current space weather
information as specifiedto functional entities identified as recipients in in the Reliability
Coordinator's GMD Operating Plan.
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Therefore, to ensure responsibility for disseminating space weather information in the Reliability
Coordinator Area is maintained while avoiding duplicative requirements being enforceable at the same
time, EOP-010-1 shall become effective as follows:
In jurisdictions where regulatory approval is required:
•
The first day of the first calendar quarter that is six months beyond after the date that this
standard is approved by an applicable governmental authorityies or as otherwise provided
for in that jurisdiction.made effective pursuant to the laws of applicable to these authorities.
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
In jurisdictions where regulatory approval is not required:
•
The first day of the first calendar quarter that is six months beyond after the date this
standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdictionmade effective pursuant to the laws of applicable governmental authorities. .
•
If EOP-010-1 becomes effective prior to the retirement of IRO-005-3.1a, Requirement R2 shall
become effective on the first day following retirement of IRO-005-3.1a.
Project 2013-03 Geomagnetic Disturbance Mitigation
Implementation Plan – October 25, 2013
2
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Standards Authorization Request Form
Standards Authorization Request Form
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):
EOP-010-1 Geomagnetic Disturbance Operations
TPL-007-1 Transmission System Planned Performance During
Geomagnetic Disturbances
Date Submitted:
SAR Requester Information
Name:
Kenneth Donohoo, Oncor
Organization:
Chair, Geomagnetic Disturbance Task Force
Telephone:
NA
E-mail:
NA
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.):
To mitigate the risk of instability, uncontrolled separation, and Cascading in the Bulk-Power System 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.
Industry Need (What is the industry problem this request is trying to solve?):
While the impacts of space weather are complex and depend on numerous factors, space weather has
demonstrated the potential to disrupt the operation of the Bulk-Power System. A technical discussion of
the effects of geomagnetic disturbances on the Bulk-Power System and recommended actions for NERC
and the industry is provided in the NERC 2012 GMD Report prepared by the GMD Task Force. During a
GMD event, geomagnetically-induced current (GIC) flow in transformers may cause half-cycle
1
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Standards Authorization Request Form
SAR Information
saturation, which can increase absorption of Reactive Power, generate harmonic currents, and cause
transformer hot spot heating. Harmonic currents may cause protection system Misoperation leading to
the loss of Reactive Power sources. The combination of these effects from GIC can lead to voltage
collapse.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will develop requirements for registered entities to employ strategies that
mitigate risks of instability, uncontrolled separation and Cascading in the Bulk-Power System caused by
GMD in two stages as directed in Order 779:
1. Stage 1 standard(s) will require applicable registered entities to develop and implement
Operating Procedures with predetermined and actionable steps to take prior to and during GMD
events which take into account entity-specific factors that can impact the severity of GMD
events in the local area. The Stage 1 standard(s) may also include associated training
requirements for System Operators or development of training requirements may be deferred to
Stage 2.
2. Stage 2 standard(s) will require applicable registered entities to conduct initial and on-going
assessments of the potential impact of benchmark GMD events on their respective system as
directed in Order 779. The Stage 2 standard(s) must identify benchmark GMD events that
specify what severity GMD events applicable registered entities must assess for potential
impacts. If the assessments identify potential impacts from benchmark GMD events, the
Standard(s) will require the registered entity to develop and implement a plan to mitigate the
risk of instability, uncontrolled separation, or Cascading as a result of benchmark GMD events.
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 standards development project will respond to the directives in FERC Order 779 in the timeframe
required by the Order and draw upon the technical products of the GMD Task Force Phase 2 Project and
other relevant information. The GMD Task Force Phase 2 Project addresses the recommendations in
the 2012 GMD Report and is focused on improving the capabilities of industry to assess GMD risk and
develop appropriate mitigation strategies.
2
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Standards Authorization Request Form
SAR Information
Operating Procedures are the first stage in the Standards project to manage risks associated with GMD
events with accompanying training requirements to be addressed in Stage 1 or 2 as determined by the
Standards Drafting Team. Specifically, the project will require owners and operators of the Bulk-Power
System to develop and implement Operating Procedures and accompanying operator training which
may include:
Procedures for acquiring and disseminating forecasting information and warning messages from
the space weather forecasting community to the System Operators;
Predetermined and actionable steps for System Operators to take prior to and during a GMD
event that are tailored to the registered entity's assessment of entity-specific factors such as
geography, geology, and system topology;
Procedures to notify and coordinate with interconnected registered entities for effective action;
Restoration procedures for applicable elements that may be impacted;
Minimum training requirements for System Operators; and
Criteria for discontinuing the use of Operating Procedures at the conclusion of a GMD event.
The second stage of the project will require applicable registered entities to conduct initial and periodic
assessments of the risk and potential impact of benchmark GMD events to the Bulk-Power System and
develop strategies to mitigate the risk of instability, uncontrolled separation, and Cascading.
The definition of benchmark GMD events will be based on reviewed technical analysis.
Periodic update of the assessments will be required to account for new Facilities and
modifications to existing Facilities. It is expected that assessments will also consider new
information and the use of new or updated tools, including new research on GMDs and the ongoing work of the NERC GMD Task Force.
The Standard(s) will require Planning Coordinators and Reliability Coordinators to review plans
addressing the potential impact of benchmark GMD events in order to provide a wide-area
perspective. The Standard Requirements for plans will be supported by reviewed technical
analysis, with consideration of the directives in FERC Order 779.
When both stages have been completed as required by FERC Order 779, all directives in the Order will
have been addressed.
3
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Standards Authorization Request Form
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.
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.
4
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Standards Authorization Request Form
Reliability Functions
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.
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
Enter
(yes/no)
Yes
Yes
Yes
5
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Authorization Request Form
Reliability and Market Interface Principles
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.
Yes
Related Standards
Standard No.
PER-005-1, R3
Explanation
Training on GMD events and mitigation procedures will be added to this
requirement as a specific element in required operator training unless included in
a separate GMD standard.
Related SARs
SAR ID
Explanation
6
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Authorization Request Form
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
The intent of the project is to develop continent-wide requirements that allow responsible entities to
tailor operational procedures or strategies based on the responsible entity's assessment of entityspecific factors such as geography, geology, and system topology. However, the need for regional
variances will be researched throughout the proposed project and may be supported by analysis
required to develop stage 2 Standard(s).
7
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators and Transmission Operators with networks
that contain power transformers with high side grounded wye windings above 200 kV. The drafting team
concluded that this is the minimum network voltage for which a reliability benefit can be expected from
the application of GMD Operating Procedures. This lower-bound threshold is consistent with operating
experience and modeling guidance provided in the literature, as explained below.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779.
Justification
Because transmission line resistance decreases by a factor of 10 from 69 kV to 765 kV and lower voltage
lines tend to be shorter (115 kV lines are typically less than 15 miles in length), the resulting
geomagnetically-induced current (GIC) generated by lines rated less than 200 kV are significantly less than
those of higher voltages and are typically ignored in GIC analysis. Conversely, using a voltage threshold
higher than 200 kV, such as 345 kV, for a lower-bound threshold could potentially create a reliability gap
by excluding a portion of the network that can be significantly affected by GMD. Results of sensitivity
analysis conducted by the drafting team are presented in the appendix. It shows that the GIC contribution
from the 230 kV portion of the network can result in system impacts during a GMD event.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Definition Considerations
Key parameters in the definition of a network for assessing GMD impacts are:
• Transformer grounding and core construction
o Only wye-grounded power transformer windings provide a path for GIC
o Transformer core construction (e.g., single-phase, three-phase, autotransformer) has an
effect on the magnitude of var absorption and generated harmonics. Single-phase
transformers are more susceptible to half-cycle saturation due to GIC relative to threephase 3-leg units; however, the var absorption in 3-legged three-phase core units cannot
be neglected.
o Regardless of core construction, all grounded wye transformers have an effect in the
distribution of GIC in the network
• System topology
• Geographical location
• Resistance values of the elements of the DC network used to evaluate GIC distribution within the
network
o Transmission line resistances per unit length increase as the voltage level decreases (see
typical values in Table 1). (With the resistances shown in Table 1, the maximum neutral
GIC contributed by a single 230 kV circuit is of the order of 30 A, as opposed to 75 A for a
single 345 kV circuit.)
Selection of a network where the cut off is selected on the basis of wye-grounded power
transformers with HV terminals > 200 kV
•
•
•
Almost all peer-reviewed studies on the effects of GIC include networks > 200 kV [1-13].
When lower voltage levels are included, the effects of including network elements < 200 kV are in
most cases minimal [9]. (The Appendix shows an example of the effects of the inclusion/exclusion
of the 115 kV network.)
The absorption of reactive power in a saturated transformer depends on the system operating
voltage and GIC. It does not depend on the nameplate rating of the transformer. In the case of
single-phase power transformers, var absorption and harmonic generation are very insensitive to
air-core reactance [11].
TABLE 1
TYPICAL NETWORK RESISTANCES FOR DIFFERENT VOLTAGE-LEVEL POWER GRIDS IN NORTH AMERICA
System
Voltage Levels
(kV)
230
345
500
735
DC Resistances
of the
Transformers
(ohm)
0.692
0.356
0.195
0.159
Grounding
Resistances of
the Substations
(ohm)
0.563
0.667
0.125
0.258
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
DC Resistances
of the
Transmission
lines (ohm/km)
0.072
0.037
0.013
0.011
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
•
Reactive power absorption of a saturated transformer is proportional to its HV voltage rating.
Transformers < 200 kV have a relatively lower influence in the reactive power balance of the
system (see Figure 1).
90
80
Q (Mvar)
70
60
500 kV
50
230 kV
40
115 kV
30
20
10
0
0
50
100
150
200
250
GIC (A/phase)
Figure 1: Reactive power absorption of a single-phase transformer vs. GIC
System Impact Considerations
A key element in a GMD event is the absorption of reactive power of high side wye-grounded
transformers experiencing half-cycle saturation.
•
•
•
In many jurisdictions bulk power transmission includes voltages > 200 kV. Tripping a transformer
with high side voltage > 200 kV or reconfiguring > 200 kV circuits can impose serious constraints on
operating limits; therefore, such operating scenarios must be considered in GMD impact studies.
Generator step-up transformers are typically situated at electrical end points of the network
where GIC tends to be highest. GSUs with high side voltages > 200 kV are not uncommon. On the
other hand, GIC injected by circuits < 200 kV is limited because of the higher resistances of GSUs
connected to < 200 kV networks
Autotransformers are often used in networks above > 200 kV. The flow of GIC depends heavily on
the relative resistances of various network elements and the geographical orientation of nearby
transmission lines [14]. Considering a 500/230 kV autotransformer with one 500 kV and one 230
kV circuit, modelling GIC flow without taking into consideration the 230 kV circuit results in GIC
overestimation between 20% and 30%. In a more complex configuration, the estimated GIC
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
•
•
ignoring the 230 kV circuits can over or underestimate GIC and the effects of GIC in transformers
significantly. The appendix shows an example of this effect.
From the point of view of GIC distribution in the network, transformer vulnerability is not a
consideration. Including only transformers with high side windings > 300 kV would result in
unrealistic GIC flow assessments (see Appendix)
In systems where the bulk transmission voltages are 230 kV and 500 kV, neglecting circuits rated
less than 300 kV would misrepresent GIC flows and var absorption, especially because GIC flowthrough in 500 kV autotransformers would be neglected (see Appendix).
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Appendix
This Appendix describes two examples where:
• The exclusion of 230 kV circuits at a station with 500/230 kV autotransformers cause significant
errors in the estimation of GIC effects.
• The inclusion/exclusion of the 161 kV and 115 kV networks in a large utility within the Eastern
Interconnect has minimal impact on the estimation of the effects of GIC in the system
Example 1: Exclusion of 230 kV circuits in a 500/230 kV transmission station
The distribution of GIC in a network, for a given geomagnetic latitude and earth structure, depends on a
number of factors such as resistances of various circuit elements, induced voltages and network topology.
There are times when a complex network topology can lead to non-intuitive results, such as the presence
of a series capacitor causing an increase of GIC in a transformer.
To illustrate, consider the topology of the circuits connected to Transmission Station (TS) shown in Fig. A1.
If a transmission circuit is sufficiently long it can be represented by a constant current source (since both
induced voltage and line resistance are proportional to line length). In the case of a 500 kV circuit, GIC
tends to be fairly constant for lengths > 150 km. A simplified representation is shown in Fig A2. The
station has several autotransformers which have been lumped into a single equivalent autotransformer.
The series capacitor bank is assumed to be out of service (bypassed).
Currents I1 and I2 represent the GIC contribution of the 500 kV circuits to the HV bus. Then,
I 3 = I1 − I 2
(A.1)
where I3 is the total contribution of the 500 kV circuits to the series winding. The total contribution to the
common winding is given by
Ig = I 3 + I 4 + I 5 + I 6 − I 7
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
(A.2)
5
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I1
Series capacitor
500 kV
230 kV
I4
230 kV
I5
I6
TS
230 kV
I2
I7
230 kV
500 kV
Fig. A1: HV transmission lines connecting to Essa TS.
I1
I4
I5
HV
I2
I3
LV
I7
Ig
I6
Fig. A2: Circuit representation of induced geoelectric fields and equivalent transformer representation.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
6
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Let us assume that the earth can be represented by a laterally-uniform earth model, and that the 500 kV
circuits are in the same or similar orientation geographically with the same resistance per unit length, so
that the injected GIC I1 and I2 are nearly identical (see Fig. A1). Then I3 will be small or zero and only the
230 kV circuits will contribute to the current in the transformer common winding Ig. If the 230 kV circuits
were excluded, (i.e., I4 = I5 = I6 = I7 = 0) then I3 = Ig would be very small and the estimated effects of GIC
on the autotransformer would be minimal.
If the 500 kV series capacitor bank in Fig. A1 is placed in service, then I1 = 0 and I2 = I3. The commonwinding GIC is now equal to the sum of the GIC contributed by the 230 kV circuits and the remaining 500
kV circuit. Depending on the relative values of the contributions, the net GIC through the transformer
may increase or decrease. Simulations show that in the network shown in Figure A1 when the series
capacitors are in service, the effective GIC through the transformer increases by a factor of 30. This is not
a general result, but rather a consequence of Kirchhoff’s current law and a particular system topology.
If the series capacitor bank is in service and the 230 kV circuits are not taken into consideration all the GIC
from the remaining 500 kV circuit would flow into the autotransformer and describe a completely
different situation from in terms of the saturation of the autotransformer.
The cases described above were simulated with a GIC analysis tool and summarized in Table A1. Note
that there are two 500/230 kV autotransformers in service in this simulation.
Table A1: Summary of the Effects of 230 kV Circuits in a Station
with Two 500/230 kV Autotransformers
Geoelectric
field
5 V/km
Transformer
GIC/phase
(A/phase)
I1 (A/phase)
I2 (A/phase)
Incremental
metallic hot spot
temperature (C°)
var absorption
(Mvar)
THD (%)
230 kV and
500 kV
500 kV Series
caps in service
230 kV and
500 kV
500 kV Series
caps bypassed
No 230 kV
500 kV Series
caps in service
No 230 kV
500 kV Series
caps bypassed
99.9
2.8
127
5.5
0
146.8
365
334
0
254
338
349
89
1.6
60
7.6
128
14
151
12.5
17
2.5
18
2.2
The conclusion from this example is that it is not always possible to make generalizations in a network of
relatively complex topology. While it is true that a series capacitor blocks GIC in the transmission line
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
7
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
where it is employed, it does not necessarily reduce GIC in system transformers. Furthermore, not taking
into account the effects of the 230 kV circuits in this network would lead to inaccurate conclusions, such
as a 33% underestimation of the hot spot temperature rise 1.
Example 2: Effects of the inclusion/exclusion of circuits below 200 kV
A portion of the Eastern Interconnect that contains 500 kV, 230 kV, 161 kV, and 115 kV facilities was
modeled using PowerWorld software. When the GIC contribution of the 161 kV and 115 kV circuits was
excluded, the effects on the network above 200 kV where found to be minimal. Table A2 summarizes the
effects of including/excluding GIC contributions from the 161 kV and 115 kV network assuming a 5 V/km
East-West geoelectric field. The differences in the results assuming a North-South geoelectric field are
very similar, and are not reproduced in here.
Table A2: GIC Effects on the Network Above 200 kV Assuming an
East-West 5 V/km Geoelectric Field
Including 115
kV
Maximum transformer GIC (A/phase)
134.65
Average transformer GIC (A/phase)
13.79
Maximum transformer var absorption 150.3
(Mvar)
Average transformer var absorption 7.16
(Mvar)
Minimum bus voltage (pu)
0.98204
Average bus voltage (pu)
1.01858
Total system var loss due to GIC (Mvar)
3,935
Excluding 115
kV
133.78
13.46
149.5
Difference
0.6 (%)
2.4 (%)
0.7 (%)
7.08
1.1 (%)
0.98548
1.01897
3,801
0.4 (%)
0.04 (%)
3.4 (%)
These results are consistent with observations made in peer-reviewed technical publications such as [9].
1
Hot spot heating was estimated using the methodology described in [15]
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
8
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
References
[1] Boteler, D., Bui-Van, Q., & Lemay, J. (1994). Directional sensitivity to geomagnetically induced currents of the
Hydro-Quebec 735 kV power system. Power Delivery, IEEE Transactions on, 9(4), 1963-1971.
[2] Boteler, D., Watanabe, T., Shier, R., & Horita, R. (1982). Characteristics of Geomagnetically Induced Currents in
the B. C. Hydro 500 kV System. Power Apparatus and Systems, IEEE Transactions on, PAS-101(6), 1447-1456.
[3] Mäkinen, T. (1992). Geomagnetically induced currents in the Finnish power transmission system. Helsinki,
Finland: Finnish Meteorological Institute.
[4] Mohan, N., Albertson, V., Speak, T., Kappenman, K., & Bahrman, M. (1982). Effects of Geomagnetically-Induced
Currents on HVDC Converter Operation. Power Apparatus and Systems, IEEE Transactions on, PAS-101(11), 44134418.
[5] Picher, P., Bolduc, L., Dutil, A., & Pham, V. (1997). Study of the acceptable DC current limit in core-form power
transformers. IEEE Transactions on Power Delivery, Vol 12, No1, 257-265.
[6] Pirjola, R. (2000). Geomagnetically induced currents during magnetic storms. Plasma Science, IEEE Transactions
on, 28(6), 1867-1873.
[7] Pirjola, R., & Boteler, D. (2006). Geomagnetically Induced Currents in European High-Voltage Power Systems.
Electrical and Computer Engineering, 2006. CCECE '06. Canadian Conference on (pp. 1263-1266). Ottawa, Canada:
IEEE.
[8] Pirjola, R., Liu, C.-m., & Liu, L.-g. (2010). Geomagnetically Induced Currents in electric power transmission
networks at different latitudes. Electromagnetic Compatibility (APEMC), 2010 Asia-Pacific Symposium on (pp. 699702). Beijing, China: IEEE.
[9] Prabhakara, F., Hannett, L., Ringlee, R., & Ponder, J. (1992). Geomagnetic effects modelling for the PJM
interconnection system. II. Geomagnetically induced current study results. Power Systems, IEEE Transactions on,
7(2), 565-571.
[10] Viljanen, A., Pirjola, R., Wik, M., Adam, A., Pracser, E., Sakharov, Y., et al. (2012). Continental scale modelling of
geomagnetically induced currents. J. Space Weather Space Clim., 3, A171-A1711.
[11] Walling, R., & Khan, A. (1991). Characteristics of transformer exciting-current during geomagnetic disturbances.
Power Delivery, IEEE Transactions on, 6(4), 1707-1714.
[12] Viljanen, A., & Pirjola, R. (1994). Geomagnetically Induced Currents in the Finnish High-Voltage
Power System: A Geophysical Review. Netherlands: Surveys in Geophysics, 15, 383-408.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
[13] Wik, M., Viljanen, A., Pirjola, R., Pulkkinen, A., Wintoft, P., & Lundstedt, H. (2008). Calculation of
Geomagnetically Induced Currents in the 400 kV Power Grid in Southern Sweden. Space Weather, Vol. 6,
S07005, 1-11.
[14] Overbye, T. J., et al, “Power Grid Sensitivity Analysis of Geomagnetically Induced Currents”, IEEE
Transactions on Power Delivery, 2013, Accepted for inclusion in a future issue, Digital Object Identifier
10.1109/TPWRS.2013.2274624.
[15] 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
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
10
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Network Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators and Transmission Operators with networks
that contain power transformers with high side grounded wye windings above 200 kV. The drafting team
concluded that this is the minimum network voltage for which a reliability benefit can be expected from
the application of GMD Operating Procedures. This lower-bound threshold is consistent with operating
experience and modeling guidance provided in the literature, as explained below.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779.
Justification
Because transmission line resistance decreases by a factor of 10 from 69 kV to 765 kV and lower voltage
lines tend to be shorter (115 kV lines are typically less than 15 miles in length), the resulting
geomagnetically-induced current (GIC) generated by lines rated less than 200 kV are significantly less than
those of higher voltages and are typically ignored in GIC analysis. Conversely, using a voltage threshold
higher than 200 kV, such as 345 kV, for a lower-bound threshold could potentially create a reliability gap
by excluding a portion of the network that can be significantly affected by GMD. Results of sensitivity
analysis conducted by the drafting team are presented in the appendix. It shows that the GIC contribution
from the 230 kV portion of the network can result in system impacts during a GMD event.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Network Definition Considerations
Key parameters in the definition of a network for assessing GMD impacts are:
• Transformer grounding and core construction
o Only wye-grounded power transformer windings provide a path for GIC
o Transformer core construction (e.ge.g., single-phase, three-phase, autotransformer) has an
effect on the magnitude of var absorption and generated harmonics. Single-phase
transformers are more susceptible to half-cycle saturation due to GIC relative to threephase 3-leg units; however, the var absorption in 3-legged three-phase core units cannot
be neglected.
o Regardless of core construction, all grounded wye transformers have an effect in the
distribution of GIC in the network
• System topology
• , including gGeographical orientationlocation
• Resistance values of the elements of the DC network used to evaluate GIC distribution within the
network
o Transmission line resistances per unit length increase as the voltage level decreases (see
typical values in Table 1). (With the resistances shown in Table 1, the maximum neutral
GIC contributed by a single 230 kV circuit is of the order of 30 A, as opposed to 75 A for a
single 345 kV circuit.)
Selection of a network where the cut off is selected on the basis of wye-grounded power
transformers with HV terminals > 200 kV
•
•
•
Almost all peer-reviewed studies on the effects of GIC include networks > 200 kV [1-13].
When lower voltage levels are included, the effects of including network elements < 200 kV are in
most cases minimal [9]. (The Appendix shows an example of the effects of the inclusion/exclusion
of the 115 kV network.)
The absorption of reactive power in a saturated transformer depends on the system operating
voltage and GIC. It does not depend on the nameplate rating of the transformer. In the case of
single-phase power transformers, var absorption and harmonic generation are very insensitive to
air-core reactance [11].
TABLE 1
TYPICAL NETWORK RESISTANCES FOR DIFFERENT VOLTAGE-LEVEL POWER GRIDS IN NORTH AMERICA
System
Voltage Levels
(kV)
230
345
500
735
DC Resistances
of the
Transformers
(ohm)
0.692
0.356
0.195
0.159
Grounding
Resistances of
the Substations
(ohm)
0.563
0.667
0.125
0.258
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
DC Resistances
of the
Transmission
lines (ohm/km)
0.072
0.037
0.013
0.011
2
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•
Reactive power absorption of a saturated transformer is proportional to its HV voltage rating.
Transformers < 200 kV have a relatively lower influence in the reactive power balance of the
system (see Figure 1).
90
80
Q (Mvar)
70
60
500 kV
50
230 kV
40
115 kV
30
20
10
0
0
50
100
150
200
250
GIC (A/phase)
Figure 1: Reactive power absorption of a single-phase transformer vs. GIC
System Impact Considerations
A key element in a GMD event is the absorption of reactive power of high side wye-grounded
transformers experiencing half-cycle saturation.
•
•
•
In many jurisdictions bulk power transmission includes voltages > 200 kV. Tripping a transformer
with high side voltage > 200 kV or reconfiguring > 200 kV circuits can impose serious constraints on
operating limits; therefore, such operating scenarios must be considered in GMD impact studies.
Generator step-up transformers are typically situated at electrical end points of the network
where GIC tends to be highest. GSUs with high side voltages > 200 kV are not uncommon. On the
other hand, GIC injected by circuits < 200 kV is limited because of the higher resistances of GSUs
connected to < 200 kV networks
Autotransformers are often used in networks above > 200 kV. The flow of GIC depends heavily on
the relative resistances of various network elements and the geographical orientation of nearby
transmission lines [14]. Considering a 500/230 kV autotransformer with one 500 kV and one 230
kV circuit, modelling GIC flow without taking into consideration the 230 kV circuit results in GIC
overestimation between 20% and 30%. In a more complex configuration, the estimated GIC
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
•
•
ignoring the 230 kV circuits can over or underestimate GIC and the effects of GIC in transformers
significantly. The appendix shows an example of this effect.
From the point of view of GIC distribution in the network, transformer vulnerability is not a
consideration. Including only transformers with high side windings > 300 kV would result in
unrealistic GIC flow assessments (see Appendix)
In systems where the bulk transmission voltages are 230 kV and 500 kV, neglecting circuits rated
less than 300 kV would misrepresent GIC flows and var absorption, especially because GIC flowthrough in 500 kV autotransformers would be neglected (see Appendix).
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Appendix
This Appendix describes two examples where:
• The exclusion of 230 kV circuits at a station with 500/230 kV autotransformers cause significant
errors in the estimation of GIC effects.
• The inclusion/exclusion of the 161 kV and 115 kV networks in a large utility within the Eastern
Interconnect has minimal impact on the estimation of the effects of GIC in the system
Example 1: Exclusion of 230 kV circuits in a 500/230 kV transmission station
The distribution of GIC in a network, for a given geomagnetic latitude and earth structure, depends on a
number of factors such as resistances of various circuit elements, induced voltages and network topology.
There are times when a complex network topology can lead to non-intuitive results, such as the presence
of a series capacitor causing an increase of GIC in a transformer.
To illustrate, consider the topology of the circuits connected to Transmission Station (TS) shown in Fig. A1.
If a transmission circuit is sufficiently long it can be represented by a constant current source (since both
induced voltage and line resistance are proportional to line length). In the case of a 500 kV circuit, GIC
tends to be fairly constant for lengths > 150 km. A simplified representation is shown in Fig A2. The
station has several autotransformers which have been lumped into a single equivalent autotransformer.
The series capacitor bank is assumed to be out of service (bypassed).
Currents I1 and I2 represent the GIC contribution of the 500 kV circuits to the HV bus. Then,
I 3 = I1 − I 2
(A.1)
where I3 is the total contribution of the 500 kV circuits to the series winding. The total contribution to the
common winding is given by
Ig = I 3 + I 4 + I 5 + I 6 − I 7
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
(A.2)
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I1
Series capacitor
500 kV
230 kV
I4
230 kV
I5
I6
TS
230 kV
I2
I7
230 kV
500 kV
Fig. A1: HV transmission lines connecting to Essa TS.
I1
I4
I5
HV
I2
I3
LV
I7
Ig
I6
Fig. A2: Circuit representation of induced geoelectric fields and equivalent transformer representation.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Let us assume that the earth can be represented by a laterally-uniform earth model, and that the 500 kV
circuits are in the same or similar orientation geographically with the same resistance per unit length, so
that the injected GIC I1 and I2 are nearly identical (see Fig. A1). Then I3 will be small or zero and only the
230 kV circuits will contribute to the current in the transformer common winding Ig. If the 230 kV circuits
were excluded, (i.e., I4 = I5 = I6 = I7 = 0) then I3 = Ig would be very small and the estimated effects of GIC
on the autotransformer would be minimal.
If the 500 kV series capacitor bank in Fig. A1 is placed in service, then I1 = 0 and I2 = I3. The commonwinding GIC is now equal to the sum of the GIC contributed by the 230 kV circuits and the remaining 500
kV circuit. Depending on the relative values of the contributions, the net GIC through the transformer
may increase or decrease. Simulations show that in the network shown in Figure A1 when the series
capacitors are in service, the effective GIC through the transformer increases by a factor of 30. This is not
a general result, but rather a consequence of Kirchhoff’s current law and a particular system topology.
If the series capacitor bank is in service and the 230 kV circuits are not taken into consideration all the GIC
from the remaining 500 kV circuit would flow into the autotransformer and describe a completely
different situation from in terms of the saturation of the autotransformer.
The cases described above were simulated with a GIC analysis tool and summarized in Table A1. Note
that there are two 500/230 kV autotransformers in service in this simulation.
Table A1: Summary of the Effects of 230 kV Circuits in a Station
with Two 500/230 kV Autotransformers
Geoelectric
field
5 V/km
Transformer
GIC/phase
(A/phase)
I1 (A/phase)
I2 (A/phase)
Incremental
metallic hot spot
temperature (C°)
var absorption
(Mvar)
THD (%)
230 kV and
500 kV
500 kV Series
caps in service
230 kV and
500 kV
500 kV Series
caps bypassed
No 230 kV
500 kV Series
caps in service
No 230 kV
500 kV Series
caps bypassed
99.9
2.8
127
5.5
0
146.8
365
334
0
254
338
349
89
1.6
60
7.6
128
14
151
12.5
17
2.5
18
2.2
The conclusion from this example is that it is not always possible to make generalizations in a network of
relatively complex topology. While it is true that a series capacitor blocks GIC in the transmission line
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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where it is employed, it does not necessarily reduce GIC in system transformers. Furthermore, not taking
into account the effects of the 230 kV circuits in this network would lead to inaccurate conclusions, such
as a 33% underestimation of the hot spot temperature rise 1.
Example 2: Effects of the inclusion/exclusion of circuits below 200 kV
A portion of the Eastern Interconnect that contains 500 kV, 230 kV, 161 kV, and 115 kV facilities was
modeled using PowerWorld software. When the GIC contribution of the 161 kV and 115 kV circuits was
excluded, the effects on the network above 200 kV where found to be minimal. Table A2 summarizes the
effects of including/excluding GIC contributions from the 161 kV and 115 kV network assuming a 5 V/km
East-West geoelectric field. The differences in the results assuming a North-South geoelectric field are
very similar, and are not reproduced in here.
Table A2: GIC Effects on the Network Above 200 kV Assuming an
East-West 5 V/km Geoelectric Field
Including 115
kV
Maximum transformer GIC (A/phase)
134.65
Average transformer GIC (A/phase)
13.79
Maximum transformer var absorption 150.3
(Mvar)
Average transformer var absorption 7.16
(Mvar)
Minimum bus voltage (pu)
0.98204
Average bus voltage (pu)
1.01858
Total system var loss due to GIC (Mvar)
3,935
Excluding 115
kV
133.78
13.46
149.5
Difference
0.6 (%)
2.4 (%)
0.7 (%)
7.08
1.1 (%)
0.98548
1.01897
3,801
0.4 (%)
0.04 (%)
3.4 (%)
These results are consistent with observations made in peer-reviewed technical publications such as [9].
1
Hot spot heating was estimated using the methodology described in [15]
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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References
[1] Boteler, D., Bui-Van, Q., & Lemay, J. (1994). Directional sensitivity to geomagnetically induced currents of the
Hydro-Quebec 735 kV power system. Power Delivery, IEEE Transactions on, 9(4), 1963-1971.
[2] Boteler, D., Watanabe, T., Shier, R., & Horita, R. (1982). Characteristics of Geomagnetically Induced Currents in
the B. C. Hydro 500 kV System. Power Apparatus and Systems, IEEE Transactions on, PAS-101(6), 1447-1456.
[3] Mäkinen, T. (1992). Geomagnetically induced currents in the Finnish power transmission system. Helsinki,
Finland: Finnish Meteorological Institute.
[4] Mohan, N., Albertson, V., Speak, T., Kappenman, K., & Bahrman, M. (1982). Effects of Geomagnetically-Induced
Currents on HVDC Converter Operation. Power Apparatus and Systems, IEEE Transactions on, PAS-101(11), 44134418.
[5] Picher, P., Bolduc, L., Dutil, A., & Pham, V. (1997). Study of the acceptable DC current limit in core-form power
transformers. IEEE Transactions on Power Delivery, Vol 12, No1, 257-265.
[6] Pirjola, R. (2000). Geomagnetically induced currents during magnetic storms. Plasma Science, IEEE Transactions
on, 28(6), 1867-1873.
[7] Pirjola, R., & Boteler, D. (2006). Geomagnetically Induced Currents in European High-Voltage Power Systems.
Electrical and Computer Engineering, 2006. CCECE '06. Canadian Conference on (pp. 1263-1266). Ottawa, Canada:
IEEE.
[8] Pirjola, R., Liu, C.-m., & Liu, L.-g. (2010). Geomagnetically Induced Currents in electric power transmission
networks at different latitudes. Electromagnetic Compatibility (APEMC), 2010 Asia-Pacific Symposium on (pp. 699702). Beijing, China: IEEE.
[9] Prabhakara, F., Hannett, L., Ringlee, R., & Ponder, J. (1992). Geomagnetic effects modelling for the PJM
interconnection system. II. Geomagnetically induced current study results. Power Systems, IEEE Transactions on,
7(2), 565-571.
[10] Viljanen, A., Pirjola, R., Wik, M., Adam, A., Pracser, E., Sakharov, Y., et al. (2012). Continental scale modelling of
geomagnetically induced currents. J. Space Weather Space Clim., 3, A171-A1711.
[11] Walling, R., & Khan, A. (1991). Characteristics of transformer exciting-current during geomagnetic disturbances.
Power Delivery, IEEE Transactions on, 6(4), 1707-1714.
[12] Viljanen, A., & Pirjola, R. (1994). Geomagnetically Induced Currents in the Finnish High-Voltage
Power System: A Geophysical Review. Netherlands: Surveys in Geophysics, 15, 383-408.
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
[13] Wik, M., Viljanen, A., Pirjola, R., Pulkkinen, A., Wintoft, P., & Lundstedt, H. (2008). Calculation of
Geomagnetically Induced Currents in the 400 kV Power Grid in Southern Sweden. Space Weather, Vol. 6,
S07005, 1-11.
[14] Overbye, T. J., et al, “Power Grid Sensitivity Analysis of Geomagnetically Induced Currents”, IEEE
Transactions on Power Delivery, 2013, Accepted for inclusion in a future issue, Digital Object Identifier
10.1109/TPWRS.2013.2274624.
[15] 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
Network Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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Functional Entity Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators (RC) and Transmission Operators (TOP) with
networks that contain power transformers with high side grounded wye windings above 200 kV. This
applicability is consistent with the NERC Functional Model and existing standards where both entities are
described as having responsibility and authority for reliable transmission operations within their scope.
The drafting team determined that Balancing Authorities (BA) should not be among the applicable
functional entities because there were no additional steps or tasks for a BA to perform beyond their
normal balancing functions to mitigate GMD events. The drafting team also determined that Generator
Operators (GOP) should not be among the applicable functional entities because any Operating
Procedures to mitigate the effects of GMD would need to be supported by an equipment-specific study
and is expected to require GMD monitoring equipment. Consistent with FERC Order No. 779, vulnerability
assessments and mitigation plans will be addressed in stage 2 of Project 2013-03 and applicability of stage
2 standards will be considered separately.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779. While the
applicability of the proposed stage 1 standard is limited to RCs and TOPs, other entities will be considered
for stage 2 as outlined in the Standards Authorization Request.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Justification for Applicable Functional Entities
Reliability Coordinator
The RC has responsibility and authority for reliable operation within the Reliability Coordinator Area
(RCA). The RC's scope includes a wide-area view with situational awareness of neighboring RCAs. The
NERC Functional Model states:
The Reliability Coordinator maintains the Real-time operating reliability of its Reliability
Coordinator Area and in coordination with its neighboring Reliability Coordinator's wide-area
view. The wide-area view includes situational awareness of its neighboring Reliability Coordinator
Areas. Its scope includes both transmission and balancing operations, and it has the authority to
direct other functional entities to take certain actions to ensure that its Reliability Coordinator
Area operates reliably.
The RC's authority is codified in IRO-001-1a which states:
R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions
to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions
shall be taken without delay, but no longer than 30 minutes.
R8. Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability
Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory
requirements. Under these circumstances, the Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity, or Purchasing-Selling Entity
shall immediately inform the Reliability Coordinator of the inability to perform the directive so that
the Reliability Coordinator may implement alternate remedial actions.
Including the RC as an applicable entity in EOP-010-1 provides the necessary coordination for planning
and real-time actions that is envisioned by the Functional Model and addresses Order No. 779 directives
to consider the coordination of Operating Procedures across regions by a functional entity with a widearea view.
Transmission Operator
Like the RC, the TOP has responsibility and authority for the reliable operation of the transmission system
within a specified area. According to the NERC Functional Model:
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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The Transmission Operator is responsible for the Real-time operating reliability of the transmission
assets under its purview, which is referred to as the Transmission Operator Area. The Transmission
Operator has the authority to take certain actions to ensure that its Transmission Operator Area
operates reliably.
The TOP's authority is established in TOP-001-1a as follows:
R1. Each Transmission Operator shall have the responsibility and clear decision-making authority to
take whatever actions are needed to ensure the reliability of its area and shall exercise specific
authority to alleviate operating emergencies.
R3. Each Transmission Operator, Balancing Authority, and Generator Operator shall comply with
reliability directives issued by the Reliability Coordinator, and each Balancing Authority and
Generator Operator shall comply with reliability directives issued by the Transmission Operator,
unless such actions would violate safety, equipment, regulatory or statutory requirements. Under
these circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform
the directive so that the Reliability Coordinator or Transmission Operator can implement alternate
remedial actions.
The 2012 GMD Report contains web links for some TOP Operating Procedures to mitigate the effects of
GMD events. Recently the GMD Task Force developed Operating Procedure templates that provide a
technical resource for TOPs to use in developing procedures based on industry best practices. Included in
the templates are actions that could be employed to mitigate the effects of GMD, such as reduction of
equipment loading, increasing reactive reserves, reconfiguration of the system, recalling outages, and Load
shedding. The templates also describe indicators of GMD conditions that could be used as trigger
conditions for steps or tasks in an entity's Operating Procedures. Detailed study of system and equipment
impacts can improve Operating Procedures. However, some procedures can be put in place without system
studies to increase situational awareness and posture the system when a GMD event is forecasted.
Justification for Omitting Functional Entities
Balancing Authority
BAs are responsible for the Real-time balancing of the system. In order to carry out that responsibility,
BAs will dispatch generation, use regulation and other ancillary services, to keep Area Control Error (ACE)
within reasonable limits while maintaining system frequency. BAs will work with the TOP to adjust voltage
schedules or redispatch generation at the request of the TOP to ensure that the transmission system is
operated within thermal, voltage, and stability limits.
The BA can be expected to address GMD impacts through use of generation. However, the BA would not
initiate actions unilaterally during a GMD event and would instead respond to the direction of the TOP
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
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and RC. As such, the independent actions that the BA would take are very limited, if any. For example, if
redispatch of generation or adjustment of voltage schedules were needed, the BA would not take those
actions without a request and the concurrence of the TOP and/or RC.
The RC and TOP will be preparing GMD Operating Plans, Operating Processes, and/or Operating
Procedures to address steps that each will be taken to address GMD impacts. Some of those steps will
require the BA to take action. As outlined above, the requirement for the BA to execute actions at the
request of the TOP or RC is clear. Given that the BA would only take action at the request of the TOP or
RC and that the required actions would be the same actions BAs take for other system events, the SDT
concludes that the BA should not be included as an applicable entity in EOP-010-1.
Generator Operator
GOPs are the functional entity that operate generating unit(s) and perform the functions of supplying
energy and reliability related services. They may be responsible for operating generator step up (GSU)
transformers that connect the generator to the transmission system. Some GSU transformers are
susceptible to geomagnetically-induced currents (GICs) during a GMD event, and operating actions are
used by some GOPs to mitigate system or equipment impacts.
An effective GOP GMD Operating Procedure to mitigate the effects of GMD would require:
1. GSU transformer study to determine expected GIC on the GSU high side neutral level at their site
(GIC/thermal rating study)
2. Ability to monitor GIC at the GSU high voltage wye-grounded winding neutral
Absent the above information, the GOP would not have the technical basis for taking steps on its own and
would instead take steps based on the RC or TOP’s Operating Plans, Processes, or Procedures. Therefore,
the SDT concludes that GOPs should be excluded as applicable entities in EOP-010-1.
Some GOPs already have GMD Operating Procedures for their equipment based on prior studies and/or
monitoring equipment. EOP-010-1 will not prohibit or interfere with a GOP's established procedure.
Furthermore, the RC and TOP will be preparing GMD Operating Plans and Operating Processes or
Procedures, respectively. Those will address steps that each will be taking to address GMD impacts,
which may include requiring one or more GOPs to take action. Existing standards provide obligations for
the GOP to execute actions when requested by the TOP or RC as described above.
Generator Owners (GOs) and GOPs are included in the Project 2013-03 Standards Authorization Request.
They will be considered for inclusion in Stage 2 standards, which will require applicable entities to conduct
vulnerability assessments and develop appropriate mitigation strategies. Such mitigation strategies could
include the development of Operating Procedures for applicable GOs and GOPs.
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
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20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Functional Entity Applicability
Project 2013-03 (Geomagnetic Disturbance Mitigation)
EOP-010-1 (Geomagnetic Disturbance Operations)
Summary Determination
The purpose of EOP-010-1 (Geomagnetic Disturbance Operations) is to mitigate the reliability impacts of
geomagnetic disturbance (GMD) events by implementing Operating Plans, Processes, and Procedures. The
proposed standard is applicable to Reliability Coordinators (RC) and Transmission Operators (TOP) with
networks that contain power transformers with high side grounded wye windings above 200 kV.with
networks above 200 kV. This applicability is consistent with the NERC Functional Model and existing
standards where both entities are described as having responsibility and authority for reliable
transmission operations within their scope. The drafting team determined that Balancing Authorities (BA)
should not be among the applicable functional entities because there were no additional steps or tasks for
a BA to perform beyond their normal balancing functions to mitigate GMD events. The drafting team also
determined that Generator Operators (GOP) should not be among the applicable functional entities
because any Operating Procedures to mitigate the effects of GMD would need to be supported by an
equipment-specific study and is expected to require GMD monitoring equipment. Consistent with FERC
Order No. 779, vulnerability assessments and mitigation plans will be addressed in stage 2 of Project
2013-03 and applicability of stage 2 standards will be considered separately.
Background
On May 16, 2013 FERC issued Order No. 779, directing NERC to develop Standards that address risks to
reliability caused by geomagnetic disturbances in two stages:
•
•
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 2014. An implementation period of sixmonths was recommended in the FERC Order.
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
of instability, uncontrolled separation, or Cascading. Stage 2 Standards must be filed by January
2015. A specific implementation period for Stage 2 was not addressed in Order 779.
EOP-010-1 is a new standard to specifically address the stage 1 directives in Order No. 779. While the
applicability of the proposed stage 1 standard is limited to RCs and TOPs, other entities will be considered
for stage 2 as outlined in the Standards Authorization Request.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Justification for Applicable Functional Entities
Reliability Coordinator
The RC has responsibility and authority for reliable operation within the Reliability Coordinator Area
(RCA). The RC's scope includes a wide-area view with situational awareness of neighboring RCAs. The
NERC Functional Model states:
The Reliability Coordinator maintains the Real-time operating reliability of its Reliability
Coordinator Area and in coordination with its neighboring Reliability Coordinator's wide-area
view. The wide-area view includes situational awareness of its neighboring Reliability Coordinator
Areas. Its scope includes both transmission and balancing operations, and it has the authority to
direct other functional entities to take certain actions to ensure that its Reliability Coordinator
Area operates reliably.
The RC's authority is codified in IRO-001-1a which states:
R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions
to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions
shall be taken without delay, but no longer than 30 minutes.
R8. Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability
Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory
requirements. Under these circumstances, the Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity, or Purchasing-Selling Entity
shall immediately inform the Reliability Coordinator of the inability to perform the directive so that
the Reliability Coordinator may implement alternate remedial actions.
Including the RC as an applicable entity in EOP-010-1 provides the necessary coordination for planning
and real-time actions that is envisioned by the Functional Model and addresses Order No. 779 directives
to consider the coordination of Operating Procedures across regions by a functional entity with a widearea view.
Transmission Operator
Like the RC, the TOP has responsibility and authority for the reliable operation of the transmission system
within a specified area. According to the NERC Functional Model:
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
The Transmission Operator is responsible for the Real-time operating reliability of the transmission
assets under its purview, which is referred to as the Transmission Operator Area. The Transmission
Operator has the authority to take certain actions to ensure that its Transmission Operator Area
operates reliably.
The TOP's authority is established in TOP-001-1a as follows:
R1. Each Transmission Operator shall have the responsibility and clear decision-making authority to
take whatever actions are needed to ensure the reliability of its area and shall exercise specific
authority to alleviate operating emergencies.
R3. Each Transmission Operator, Balancing Authority, and Generator Operator shall comply with
reliability directives issued by the Reliability Coordinator, and each Balancing Authority and
Generator Operator shall comply with reliability directives issued by the Transmission Operator,
unless such actions would violate safety, equipment, regulatory or statutory requirements. Under
these circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform
the directive so that the Reliability Coordinator or Transmission Operator can implement alternate
remedial actions.
The 2012 GMD Report contains web links for some TOP Operating Procedures to mitigate the effects of
GMD events. Recently the GMD Task Force developed Operating Procedure templates that provide a
technical resource for TOPs to use in developing procedures based on industry best practices. Included in
the templates are actions that could be employed to mitigate the effects of GMD, such as reduction of
equipment loading, increasing reactive reserves, reconfiguration of the system, recalling outages, and Load
shedding. The templates also describe indicators of GMD conditions that could be used as trigger
conditions for steps or tasks in an entity's Operating Procedures. Detailed study of system and equipment
impacts can improve Operating Procedures. However some procedures can be put in place by all TOPs
without system studies to increase situational awareness and posture the system when a GMD event is
forecasted.
Justification for Omitting Functional Entities
Balancing Authority
BAs are responsible for the Real-time balancing of the system. In order to carry out that responsibility,
BAs will dispatch generation, use regulation and other ancillary services, to keep Area Control Error (ACE)
within reasonable limits while maintaining system frequency. BAs will work with the TOP to adjust voltage
schedules or redispatch generation at the request of the TOP to ensure that the transmission system is
operated within thermal, voltage, and stability limits.
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
The BA can be expected to address GMD impacts through use of generation. However, the BA would not
initiate actions unilaterally during a GMD event and would instead respond to the direction of the TOP
and RC. As such, the independent actions that the BA would take are very limited, if any. For example, if
redispatch of generation or adjustment of voltage schedules were needed, the BA would not take those
actions without a request and the concurrence of the TOP and/or RC.
The RC and TOP will be preparing GMD Operating Plans, Operating Processes, and/or Operating
Procedures to address steps that each will be taken to address GMD impacts. Some of those steps will
require the BA to take action. As outlined above, the requirement for the BA to execute actions at the
request of the TOP or RC is clear. Given that the BA would only take action at the request of the TOP or
RC and that the required actions would be the same actions BAs take for other sytemsystem events, the
SDT concludes that the BA should not be included as an applicable entity in EOP-010-1.
Generator Operator
GOPs are the functional entity that operate generating unit(s) and perform the functions of supplying
energy and reliability related services. They may be responsible for operating generator step up (GSU)
transformers that connect the generator to the transmission system. Some GSU transformers are
susceptible to geomagnetically-induced currents (GICs) during a GMD event, and operating actions are
used by some GOPs to mitigate system or equipment impacts.
An effective GOP GMD Operating Procedure to mitigate the effects of GMD would require:
1. GSU transformer study to determine expected GIC on the GSU high side neutral level at their site
(GIC/thermal rating study)
2. Ability to monitor GIC at the GSU high voltage wye-grounded winding neutral
Absent the above information, the GOP would not have the technical basis for taking steps on its own and
would instead take steps based on the RC or TOP’s Operating Plans, Processes, or Procedures. Therefore,
the SDT concludes that GOPs should be excluded as applicable entities in EOP-010-1.
Some GOPs already have GMD Operating Procedures for their equipment based on prior studies and/or
monitoring equipment. EOP-010-1 will not prohibit or interfere with a GOP's established procedure.
Furthermore, the RC and TOP will be preparing GMD Operating Plans and Operating Processes or
Procedures, respectively. Those will address steps that each will be taking to address GMD impacts,
which may include requiring one or more GOPs to take action. Existing standards provide obligations for
the GOP to execute actions when requested by the TOP or RC as described above.
Generator Owners (GOs) and GOPs are included in the Project 2013-03 Standards Authorization Request.
They will be considered for inclusion in Stage 2 standards, which will require applicable entities to conduct
vulnerability assessments and develop appropriate mitigation strategies. Such mitigation strategies could
include the development of Operating Procedures for applicable GOs and GOPs.
EOP-010-1 Functional Entity Applicability: Project 2013-03 (Geomagnetic Disturbance Mitigation)
4
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Geomagnetic Disturbance
Operating Procedure Template
Transmission Operator
Overview
Operating procedures are the quickest way to put in place actions that can mitigate the adverse effects of
geomagnetically induced currents (GIC) on system reliability. They also have the merit of being relatively
easy to change as new information and understanding concerning this threat becomes available.
Operating procedures need to be easily understood by, and provide clear direction to, operating
personnel. This is especially true since most operators are unlikely to frequently respond to significant
GMD events.
Some actions listed below should only be undertaken if supported by an adequate GIC impact study
and/or if adequate monitoring systems are available. Otherwise they can make matters worse. Those
actions are indicated by the phrase "if supported by studies".
Determining that a geomagnetic disturbance (GMD) is significant enough to warrant the initiation of
special operating procedure(s) depends on the geographical location of the power system/equipment in
question coincident with the location of the GMD measurement and forecast. Amount of advance notice
obviously factor heavily in what specific actions can and should be taken. Note these are recommended
actions; specific actions may vary by system configuration, system design and geographic location of the
entity.
Information and Indications
The following are triggers that could be used to initiate operator action:
• External:
o NOAA Space Weather Prediction Center or other organization issues:
Geomagnetic storm Watch (1-3 day lead time)
Geomagnetic storm Warning (as early as 15-60 minutes before a storm, and
updated as solar storm characteristics change)
Geomagnetic storm Alert (current geomagnetic conditions updated as k-index
thresholds are crossed )
• Internal:
o System-wide:
Reactive power reserves
System voltage/MVAR swings/current harmonics
o Equipment-level:
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
GIC measuring devices
Abnormal temperature rise (hot-spot) and/or sudden significant gassing (where online DGA available) in transformers
System or equipment relay action (e.g., capacitor bank tripping)
Actions Available to the Operator
The following are possible actions for Transmission Operators based on available lead-time:
Long lead-time (1-3 days in advance, storm possible)
1. Increase situational awareness
a. Assess readiness of black start generators and cranking paths
b. Notify field personnel as necessary of the potential need to report to individual substations
for on-site monitoring (if not available via SCADA/EMS)
2. Safe system posturing (only if supported by study; allows equipment such as transformers and
SVCs to tolerate increase reactive/harmonic loading; reduces transformer operating temperature,
allowing additional temperature rise from core saturation; prepares for contingency of possible
loss of transmission capacity)
a. Return outaged equipment to service (especially series capacitors where installed)
b. Delay planned outages
c. Remove shunt reactors
d. Modify protective relay settings based on predetermined harmonic data corresponding to
different levels of GIC (provided by transformer manufacturer).
Day-of-event (hours in advance, storm imminent):
1. Increase situational awareness
a. Monitor reactive reserve
b. Monitor for unusual voltage, MVAR swings, and/or current harmonics
c. Monitor for abnormal temperature rise/noise/dissolved gas in transformers 1
d. Monitor geomagnetically induced current (GIC 2) on banks so-equipped 3
e. Monitor MVAR loss of all EHV transformers as possible
1
Requires proper instrumentation (e.g., fiber to hot-spot). Note there may be unusual heating in a location other than the normal hot-spot
location. Dissolved gas analysis may be available in real-time if the transformer is so-equipped; otherwise, post-event DGA may be
performed.
2
10 amperes per phase GIC is a good starting point for potential impacts on heavily loaded transformers when actual limits are unknown.
Newer transformers may have significantly higher GIC withstand capability if specified at the time of construction. For vulnerable
transformers, the OEM can perform analytical withstand studies to better define a particular design's GIC vs. Time withstand capability
3
Regarding the effects of GIC on transformers, real-time mitigation (after a storm is already in progress) should not be taken based solely on
a single indicator (e.g., increased GIC). At least one additional indicator should be monitored to determine if the transformer is actually being
adversely affected (e.g., increased MVAR loss, abnormal temperature rise, etc)
Operating Procedure Template for Transmission Operators
2
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
f. Prepare for unplanned capacitor bank/SVC/HVDC tripping4
g. Prepare for possible false SCADA/EMS indications if telecommunications systems are
disrupted (e.g., over microwave paths)
2. Safe system posturing (only if supported by study)
a. Start off-line generation, synchronous condensers
b. Enter conservative operations with possible reduced transfer limits
c. Ensure series capacitors are in-service (where installed)
Real-time actions (based on results of day-of-event monitoring):
1. Safe system posturing (only if supported by study)
a. Selective load shedding 5
b. Manually start fans/pumps on selected transformers to increase thermal margin (check
that oil temperature is above 50° C as forced oil flow at lower temperatures may cause
static electrification)
2. System reconfiguration (only if supported by study)
a. Remove transformer(s) from service if imminent damage due to overheating (possibly
automatic by relaying)
b. Remove transmission line(s) from service (especially lines most influenced by GMD)
Return to normal operation
This should occur two to four hours after the last observed geomagnetic activity.
Related Documents and Links
2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbance on the Bulk Power
System, dated February 2012
http://www.nerc.com/files/2012GMD.pdf
Industry Advisory: Preparing for Geomagnetic Disturbances, dated May 10, 2011
http://www.nerc.com/fileUploads/File/Events%20Analysis/A-2011-05-10-01_GMD_FINAL.pdf
4
Consideration should be given to replacing protective relaying (as part of planned GIC mitigation projects) to prevent false
tripping of reactive assets due to GIC should be considered. Note that capacitor units have harmonic overload limits that
should be observed (see IEEE Std 18).
5
Giving preference of course to the most critical/sensitive loads (e.g., national security, nuclear fuel storage site, nuclear plant offsite
sources, chemical plants, emergency response centers, hospitals, etc)
Operating Procedure Template for Transmission Operators
3
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Agenda Item 8
Standards Committee
October 17, 2013
Project 2013-03 Geomagnetic Disturbance (GMD) Mitigation
Action
Authorize a contingent waiver of the Standard Processes Manual (SPM) that shortens the final
(recirculation) ballot period for the stage 1 standard, EOP-010-1 Geomagnetic Disturbance
Operations, from 10 days to seven days to meet the FERC-directed filing schedule and NERC
Board of Trustees (Board) meeting schedule, to be exercised only if 1) EOP-010-1 receives
sufficient support during the current ballot to proceed to final (recirculation) ballot, and 2) the
shortened time is necessary (as jointly determined by the NERC Standards Developer, PMOS
Liaison and Chair of the SDT) to provide the drafting team adequate opportunity to fully
consider stakeholder comments and prepare and review documents for posting for the final
ballot.
Background
On May 16, 2013, FERC issued Order 779 directing NERC to develop and submit Reliability
Standards addressing the potential impact of GMDs in two stages:
Stage 1 Standard(s) that require applicable entities to develop and implement Operating
Procedures. Stage 1 Standard(s) must be filed by January 21, 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 of instability, uncontrolled separation, or
Cascading. Stage 2 Standards must be filed by January 21, 2015.
The initial draft of EOP-010-1 was posted for 45-day formal comment period and initial ballot
through August 12, 2013, and received a weighted segment approval of 62.74%. A revised draft
of EOP-010-1 was posted for 45-day formal comment and additional ballot on September 4,
2013. The ballot period ends on October 18, 2013. The drafting team is scheduled to meet
October 23-24, 2013 to consider comments and revise the draft standard if necessary.
The NERC Board meeting on November 7, 2013 is the last scheduled board meeting prior to the
FERC filing deadline for the stage 1 standard. Because of the high profile nature of Project 201303 (GMD Mitigation), the drafting team recognizes that it is particularly appropriate for the
standard to be submitted to the NERC Board for adoption during the Board’s quarterly meeting,
if possible. This will ensure the standard is considered for adoption under NERC's normal open
and transparent process without special arrangements for a NERC Board conference call.
The drafting team has maintained a rigorous development and communication effort in order
to reach the November NERC Board meeting milestone. In order to complete a 10-day final
ballot in time for the Board to adopt EOP-010-1 at that meeting, the team would need to post
for the final ballot on Friday, October 25. If EOP-010-1 receives sufficient approval during the
current ballot, a waiver of the SPM that would shorten the final ballot period from 10 days to
seven days would provide a significant amount of additional time for the team to review the
final set of documents prior to posting, by allowing them to post as late as October 30.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Agenda Item 8
Standards Committee
October 17, 2013
As required in Section 16.0 of the SPM, NERC provided stakeholders with notice of this waiver
request on October 10, 2013. If the waiver is authorized, NERC staff will post notice of the
waiver on the project page and notify the NERC Board of Trustees Standards Oversight and
Technology Committee.
Violation Risk Factor and Violation Severity Level
Justifications
EOP-010-1 − Geomagnetic Disturbance Operations
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 EOP-010-1 – Geomagnetic Disturbance Operations.
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 Standard Drafting Team applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSL 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 Violation Risk Factors 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
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
2
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
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 Violation Risk Factor assignments and the main Requirement
Violation Risk Factor assignment.
Guideline (3) – Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors 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 Violation Risk Factor 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
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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
3
Violation severity levels 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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
5
VRF Justifications – EOP-010-1, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to implement a GMD Operating Plan when warranted by conditions could directly affect the
electrical state or the capability of the Bulk Electric System (BES). However, failure to implement a
GMD Operating Plan is unlikely to lead to BES instability, separation, or cascading failures. The
Reliability Coordinator and applicable entities are responsible for maintaining the reliability of the BES
under all circumstances. Failure to develop or maintain a GMD Operating Plan could, under
anticipated conditions, directly and adversely affect the electrical state or capability of the Bulk
Electric System. However, failure to develop or maintain a GMD Operating Plan is unlikely to lead to
BES instability, separation, or cascading failures, or to hinder restoration to normal conditions. This
VRF reflects the drafting team's view of the importance of having coordinated GMD Operating
Procedures and the RC's role in the planning and operations time horizons.
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. The requirement uses Parts to identify the items to be included in a GMD
Operating Plan. The VRF for this requirement is consistent with Requirement R3 with regard to
relative risk.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with IRO 014-1 Requirement R1, which requires the Reliability Coordinator to have Operating
Procedures, Processes, or Plans in place to support interconnection reliability. The drafting team
believes the reliability objective of IR0-014-1 Requirement R1 is most comparable to the proposed
Requirement R1.
Guideline 4- Consistency with NERC Definitions of VRFs. A Violation Risk Factor of Medium is
consistent with NERC VRF definition. Failure to implement a GMD Operating Plan when warranted by
conditions could directly affect the electrical state or the capability of the Bulk Electric System (BES).
However, failure to implement a GMD Operating Plan is unlikely to lead to BES instability, separation,
FERC VRF G3 Discussion
FERC VRF G4 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
6
VRF Justifications – EOP-010-1, R1
FERC VRF G5 Discussion
or cascading failures. The Reliability Coordinator and applicable entities are responsible for
maintaining the reliability of the BES under all circumstances. Failure to develop or maintain a GMD
Operating Plan could, under anticipated conditions, directly and adversely affect the electrical state
or capability of the Bulk Electric System. However, failure to develop or maintain a GMD Operating
Plan is unlikely to lead to BES instability, separation, or cascading failures, or to hinder restoration to
normal conditions. This VRF reflects the drafting team's view of the significance of the RC's role in
coordinating GMD Operating Procedures in the planning and operations time horizons.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. The assigned risk
level reflects the most important objective of the requirement.
Proposed VSLs – EOP-010-1, R1
Lower
The Reliability Coordinator had a
GMD Operating Plan, but failed
to maintain it.
Moderate
N/A
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
High
The Reliability Coordinator's
GMD Operating Plan failed to
include one of the required
elements as listed in
Requirement R1, parts 1.1 or 1.2
Severe
The Reliability Coordinator did
not have a GMD Operating Plan
OR
The Reliability Coordinator failed
to implement a GMD Operating
Plan within its Reliability
Coordinator Area
7
VSL Justifications – EOP-010-1, R1
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 VSL describes degrees of noncompliant performance in an
incremental manner.
There is no prior compliance obligation related to the subject of this standard.
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.
The proposed VSL is worded consistently with the corresponding requirement.
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
8
with the Corresponding
Requirement
The proposed VSL is not based on 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 – EOP-010-1, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to disseminate forecasted and current space weather information could directly and adversely
affect the electrical state or capability of the Bulk Electric System during a GMD event. However, failure
to disseminate forecasted and current space weather information is unlikely to lead to BES instability,
separation, or cascading failures. The Reliability Coordinator and applicable entities are responsible for
maintaining the reliability of the BES under all circumstances. This requirement and VRF reflects the
drafting team's view of the significance of consistent space weather information for coordination of
GMD Operating Procedures in each Reliability Coordinator Area and maintains responsibility for
providing this information on the Reliability Coordinator as established in IRO-005-3.1a.
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 and a
single VRF.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with IRO-008-1 Requirement R3 which requires the Reliability Coordinator to share information with
specific entities that are expected to take operational actions when a potential Interconnection
FERC VRF G3 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
9
VRF Justifications – EOP-010-1, R2
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Reliability Operating Limit violation is anticipated. Dissemination of space weather forecast information
can be considered a similar information sharing activity with an impact that would not exceed IRO-008-1
Requirement R3.
Guideline 4- Consistency with NERC Definitions of VRFs. Failure to disseminate forecasted and current
space weather information could directly and adversely affect the electrical state or capability of the
Bulk Electric System during a GMD event. However, failure to disseminate forecasted and current space
weather information is unlikely to lead to BES instability, separation, or cascading failures. The Reliability
Coordinator and applicable entities are responsible for maintaining the reliability of the BES under all
circumstances. This requirement and VRF reflects the drafting team's view of the significance of
consistent space weather information for coordination of GMD Operating Procedures in each Reliability
Coordinator Area and maintains responsibility for providing this information on the Reliability
Coordinator as established in IRO-005-3.1a.
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 – EOP-010-1, R2
Lower
N/A
Moderate
N/A
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
High
N/A
Severe
The Reliability Coordinator failed
to disseminate forecasted and
current space weather
information to all functional
entities identified as recipients in
the Reliability Coordinator's
GMD Operating Plan.
10
VSL Justifications – EOP-010-1, 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
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
Consistent with NERC's VSL Guidelines. The drafting team believes that a single VSL is most appropriate
for describing noncompliant performance of the requirement. Dissemination of space weather
information will most likely be accomplished using automated communication systems such as all-call or
electronic distribution lists. As a result the RC's compliance will be evaluated on a binary basis for
implementing a notification system to disseminate space weather information.
The current level of compliance is not lowered with the proposed VSL. IRO-005-3.1a requirement R3
provided a similar compliance obligation without a FERC-approved VSL.
The proposed VSL is written to ensure uniformity and consistency in the determination of penalties.
Guideline 2a: The proposed VSL assignment category for a binary requirement is consistent.
Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency
in the determination of similar penalties for similar violations.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
11
VSL Justifications – EOP-010-1, R2
Ambiguous Language
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 number of violations.
VRF Justifications – EOP-010-1, R3
Proposed VRF
NERC VRF Discussion
Medium
Failure to implement a GMD Operating Procedure or Operating Process when warranted by conditions
could directly affect the electrical state or the capability of the Bulk Electric System (BES). However, this
failure is unlikely to lead to BES instability, separation, or cascading failures. The Transmission Operator
and other applicable entities are responsible for maintaining the reliability of the BES under within their
respective areas in all circumstances. Failure to develop or maintain a GMD Operating Procedure or
Operating Process could, under anticipated conditions, directly and adversely affect the electrical state
or capability of the Bulk Electric System. However, this failure is unlikely to lead to BES instability,
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
12
VRF Justifications – EOP-010-1, R3
separation, or cascading failures, or to hinder restoration to normal conditions. This VRF reflects the
drafting team's view of the importance of developing and maintaining coordinated and predetermined
operating procedures or processes in the planning horizon, and for implementing the operating
procedures or processes when conditions warrant in the operations time horizon.
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. The requirement uses Parts to identify the items to be included in a GMD
Operating Procedure or Operating Process. The VRF for this requirement is consistent with Requirement
R1 with regard to relative risk.
Guideline 3- Consistency among Reliability Standards. A Violation Risk Factor of Medium is consistent
with EOP 001-2.1b, requirement R2.2 which requires the Transmission Operator to develop, maintain,
and implement plans to mitigate operating emergencies on the transmission system. Additionally, it is
consistent with IRO 014-1 Requirement R1, which requires the Reliability Coordinator to have Operating
Procedures, Processes, or Plans in place to support interconnection reliability. Although the functional
entities are different, the reliability objective of IR0-014-1 Requirement R1 is comparable to the
proposed Requirement R3.
Guideline 4- Consistency with NERC Definitions of VRFs. Failure to implement a GMD Operating
Procedure or Operating Process when warranted by conditions could directly affect the electrical state
or the capability of the Bulk Electric System (BES). However, this failure is unlikely to lead to BES
instability, separation, or cascading failures. The Transmission Operator and other applicable entities are
responsible for maintaining the reliability of the BES under within their respective areas in all
circumstances. Failure to develop or maintain a GMD Operating Procedure or Operating Process could,
under anticipated conditions, directly and adversely affect the electrical state or capability of the Bulk
Electric System. However, this failure is unlikely to lead to BES instability, separation, or cascading
failures, or to hinder restoration to normal conditions. This VRF reflects the drafting team's view of the
FERC VRF G3 Discussion
FERC VRF G4 Discussion
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
13
VRF Justifications – EOP-010-1, R3
FERC VRF G5 Discussion
importance of developing and maintaining coordinated and predetermined operating procedures or
processes in the planning horizon, and for implementing the operating procedures or processes when
conditions warrant in the operations time horizon.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation. The assigned risk
level reflects the most important objective of the requirement.
Proposed VSLs – EOP-010-1, R3
Lower
The Transmission Operator had a
GMD Operating Procedure or
Operating Process, but failed to
maintain it.
Moderate
The Transmission Operator's
GMD Operating Procedure or
Operating Process failed to
include one of the required
elements as listed in
Requirement R3, parts 3.1
through 3.3.
High
The Transmission Operator's
GMD Operating Procedure or
Operating Process failed to
include two or more of the
required elements as listed in
Requirement R3, parts 3.1
through 3.3.
Severe
The Transmission Operator did
not have a GMD Operating
Procedure or Operating Process
OR
The Transmission Operator failed
to implement its GMD Operating
Procedure or Operating Process.
VSL Justifications – EOP-010-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence of
Lowering the Current Level of
There is no prior compliance obligation related to the subject of this standard.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
14
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
Cumulative Number of
Violations
The proposed VSL is not based on 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.
EOP-010-1 − Geomagnetic Disturbance Operations
VRF and VSL Justifications
15
Commission Directives in Order No. 779, Reliability Standards for Geomagnetic Disturbances, 143 FERC ¶ 61,147 (2013)
Stage 1, EOP-010-1
Order No. 779
Citation
P 36
Directive/Guidance
The Commission directs NERC to submit, within six months of the effective
date of this Final Rule, one or more Reliability Standards requiring owners
and operators of the Bulk-Power System to develop and implement
operational procedures to mitigate the effects of GMDs consistent with the
reliable operation of the Bulk-Power System.
Resolution in EOP-010-1
Requirement R1 requires Reliability
Coordinators to develop, maintain, and
implement a GMD Operating Plan that
coordinates GMD Operating Procedures or
Operating Processes within its Reliability
Coordinator Area.
Requirement R3 requires Transmission
Operators to develop, maintain, and implement a
GMD Operating Procedure or Operating Process
to mitigate the effects of GMD events on the
reliable operation of its respective system.
P 38
The Commission is not directing NERC to develop Reliability Standards
that include specific operational procedures. Instead, as proposed in the
NOPR, the Reliability Standards should include a mechanism that requires
responsible entities to develop and implement operational procedures
because owners and operators of the Bulk-Power System are most familiar
with their own equipment and system configurations. In addition, we do not
expect that owners and operators of the Bulk-Power System will necessarily
develop and implement the same operational procedures. Instead, the
Reliability Standards, rather than include “one-size-fits-all” Requirements,
should allow responsible entities to tailor their operational procedures based
on the responsible entity’s assessment of entity-specific factors, such as
geography, geology, and system topology, identified in the Reliability
Standards. In addition, as we stated in the NOPR, the coordination of
operational procedures across regions is an important issue that should be
considered in the NERC standards development process.68 The coordination
Analysis of the applicable functional entities is
provided in a white paper posted on the project
page.
(http://www.nerc.com/pa/Stand/Pages/Project2013-03-Geomagnetic-DisturbanceMitigation.aspx)
EOP-010-1 is not prescriptive and allows entities
to tailor their Operational Procedures or
Operating Processes based on the responsible
entity’s assessment of entity-specific factors,
such as geography, geology, and system
topology.
Requirement R1 addresses coordination and
requires Reliability Coordinators to develop,
maintain and implement a GMD Operating Plan
that coordinates GMD Operating Procedures or
Operating Processes within its Reliability
Coordinator Area.
The coordination of Operating Procedures and
Order No. 779
Citation
Directive/Guidance
Resolution in EOP-010-1
of operational procedures across regions and data sharing might be overseen
by planning coordinators or another functional entity with a wide-area
perspective.69 The NERC standards development process, as stated in the
NOPR, should also consider operational procedures for restoring GMDimpacted portions of the Bulk-Power System that take into account the
potential for damaged equipment that could be de-rated or out-of-service for
an extended period of time.
2
Operating Processes across regions is addressed
through existing Reliability Standards.
EOP-005 (System Restoration from Blackstart
Resources) and EOP-006 (System Restoration
Coordination) address Bulk-Power System
restoration following a Disturbance. These plans
are expected to be effective for restoration
following any unplanned event. A duplicative
requirement was not included in EOP-010-1.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
A Final Ballot is now open through November 4, 2013
Now Available
A final ballot for EOP-010-1 – Geomagnetic Disturbance Operations is open through 8 p.m. Eastern
on Monday, November 4, 2013.
On October 17, 2013, the Standards Committee approved a waiver of the Standard Processes
Manual to shorten the final ballot from ten days to seven days only if necessary. After reviewing the
comments, the standard drafting team determined that they would not need to exercise the waiver
and the standard could be posted for the usual 10-day final ballot in order to meet the FERC-directed
filing schedule and NERC Board of Trustees meeting schedule.
Background information for this project can be found on the project page.
Instructions
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their previously cast votes. A ballot pool member who failed to
cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a ballot pool
member does not participate in the final ballot, that member’s vote cast in the previous ballot will be
carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps
Voting results for the standard will be posted and announced after the ballot window closes. If
approved, the standard will be submitted to the Board of Trustees for adoption.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Standards Announcement
Project 2013-03 Geomagnetic Disturbance Mitigation
EOP-010-1
Final Ballot Results
Now Available
A final ballot for EOP-010-1 – Geomagnetic Disturbance Operations concluded at 8 p.m. Eastern on
Monday, November 4, 2013.
This standard achieved a quorum and sufficient affirmative votes for approval. Voting statistics are
listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Approval
Quorum: 86.90%
Approval: 91.95%
Background information for this project can be found on the project page.
Next Steps
The standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2013-03 GMD Final Ballot October 2013
Password
Ballot Period: 10/25/2013 - 11/4/2013
Ballot Type: Final Ballot
Log in
Total # Votes: 345
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 397
Quorum: 86.90 % The Quorum has been reached
Weighted Segment
91.95 %
Vote:
Ballot Results: The standard has passed
Home Page
ummary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
105
1
79
0.919
7
0.081
0
9
10
10
0.7
7
0.7
0
0
0
1
2
91
1
66
0.971
2
0.029
0
10
13
30
1
17
0.81
4
0.19
0
4
5
89
1
61
0.91
6
0.09
0
12
10
54
1
37
0.902
4
0.098
0
3
10
1
0.1
1
0.1
0
0
0
0
0
6
0.5
4
0.4
1
0.1
0
0
1
3
0.2
2
0.2
0
0
0
0
1
8
0.8
8
0.8
0
0
0
0
0
397
7.3
282
6.712
24
0.588
0
39
52
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Segment
Organization
Member
Ballot
1
1
1
Ameren Services
American Electric Power
American Transmission Company, LLC
Eric Scott
Paul B Johnson
Andrew Z Pusztai
1
Arizona Public Service Co.
Robert Smith
1
1
1
1
1
1
1
1
1
1
1
1
John Bussman
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
Abstain
Affirmative
Michael Moltane
Affirmative
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Associated Electric Cooperative, Inc.
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
1
Nebraska Public Power District
Cole C Brodine
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
New Brunswick Power Transmission
Randy MacDonald
Corporation
New York Power Authority
Bruce Metruck
Northeast Missouri Electric Power Cooperative Kevin White
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
Affirmative
Affirmative
Affirmative
Negative
NERC
Notes
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
1
Oklahoma Gas and Electric Co.
Terri Pyle
1
1
1
1
1
1
1
1
1
1
1
1
1
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
1
Tucson Electric Power Co.
John Tolo
1
1
1
1
1
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
American Public Power Association
Associated Electric Cooperative, Inc.
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters
Nathan Mitchell
Chris W Bolick
1
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
Bryan Griess
Tracy Sliman
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Bartow, Florida
City of Farmington
City of Garland
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Dennis M Schmidt
Andrew Gallo
Matt Culverhouse
Linda R Jacobson
Ronnie C Hoeinghaus
Bill Hughes
Bill R Fowler
Roger Powers
Michelle A Corley
Charles Morgan
John Bee
Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
3
Oklahoma Gas and Electric Co.
Donald Hargrove
3
3
3
3
3
3
3
3
3
3
3
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
4
Blue Ridge Power Agency
Duane S Dahlquist
4
Reza Ebrahimian
4
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
4
City Utilities of Springfield, Missouri
John Allen
4
Nicholas Zettel
4
4
4
4
4
4
4
5
5
5
Arizona Public Service Co.
5
5
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Steve Wenke
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc.
Shari Heino
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Tim Beyrle
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
4
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Margaret Powell
Affirmative
Tracy Goble
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Jack Alvey
Christopher Plante
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Henry E. LuBean
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Affirmative
Affirmative
Affirmative
Scott Takinen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
5
5
5
5
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
5
CPS Energy
Robert Stevens
5
5
5
5
5
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
5
5
5
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
5
Nebraska Public Power District
Don Schmit
5
5
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Bernard Johnson
5
Oklahoma Gas and Electric Co.
Henry L Staples
5
5
5
5
5
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
Mahmood Z. Safi
David Ramkalawan
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Dana Showalter
Gustavo Estrada
John R Cashin
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando
Affirmative
Abstain
David Gordon
Affirmative
Steven Grego
Neil D Hammer
Mike Avesing
Affirmative
Abstain
Affirmative
5
PowerSouth Energy Cooperative
Tim Hattaway
5
5
5
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Annette M Bannon
Tim Kucey
Steven Grega
5
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Michiko Sell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Review
Group
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Alabama Electric Coop. Inc.
Ameren Energy Marketing Co.
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Erika Doot
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Liam Noailles
Edward P. Cox
Ron Graham
Jennifer Richardson
6
APS
Randy A. Young
6
6
6
6
6
6
6
6
6
6
6
6
6
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
FirstEnergy Solutions
Florida Municipal Power Agency
Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
Richard L. Montgomery
6
Florida Municipal Power Pool
Thomas Washburn
6
6
6
6
6
6
6
6
6
6
6
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
6
Northern California Power Agency
Steve C Hill
6
6
6
6
6
6
6
6
6
6
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Joseph O'Brien
Alan Johnson
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
NERC
Standards
20131114-5150
FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown
Seattle City Light
Dennis Sismaet
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Snohomish County PUD No. 1
Kenn Backholm
Southern California Edison Company
Lujuanna Medina
Southern Company Generation and Energy
John J. Ciza
Marketing
Tacoma Public Utilities
Michael C Hill
Tampa Electric Co.
Benjamin F Smith II
Tennessee Valley Authority
Marjorie S. Parsons
Westar Energy
Grant L Wilkerson
Western Area Power Administration - UGP
Peter H Kinney
Marketing
Wisconsin Public Service Corp.
David Hathaway
Xcel Energy, Inc.
David F Lemmons
Alcoa, Inc.
Thomas Gianneschi
Roger C Zaklukiewicz
Edward C Stein
Debra R Warner
Foundation for Resilient Societies
William R Harris
Massachusetts Attorney General
Frederick R Plett
Volkmann Consulting, Inc.
Terry Volkmann
Commonwealth of Massachusetts Department
Donald Nelson
of Public Utilities
Michigan Public Service Commission
Donald J Mazuchowski
National Association of Regulatory Utility
Diane J. Barney
Commissioners
Florida Reliability Coordinating Council
Linda Campbell
Midwest Reliability Organization
Russel Mountjoy
New York State Reliability Council
Alan Adamson
Northeast Power Coordinating Council
Guy V. Zito
ReliabilityFirst Corporation
Anthony E Jablonski
SERC Reliability Corporation
Joseph W Spencer
Texas Reliability Entity, Inc.
Donald G Jones
Western Electricity Coordinating Council
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=463abb40-9352-4920-a0e2-7bb7bffe56e3[11/5/2013 12:24:59 PM]
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Exhibit I
Standard Drafting Team Roster
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Project 2013-03 Geomagnetic Disturbance Mitigation
Name and Title
Company
Contact Info
Bio
Frank Koza, P.E.
Chair
PJM
Interconnection
610.666.4228
Executive Director of Infrastructure
Planning and in charge of the
technical staff associated with
generator interconnection and
implementation of transmission
enhancements. Vice Chair of GMD
Task Force. At PJM over 12 years,
previously in charge of system
operations. Former Chair of the
NERC Operating Reliability
Subcommittee and Reliability
Assessments Subcommittee. Before
PJM, worked for 29 years at
Exelon/PECO Energy in a variety of
assignments including construction
of fossil and nuclear generation
facilities, construction and
maintenance of transmission, system
planning, and system operations. MS
Engineering
Chief Engineer of Southern Company
Services Transmission Technical
Support. Leader of GMD Task Force
GIC Model Development team. Held
various engineering positions within
the Protective Equipment
Applications (system protection) and
Technical Studies groups of Alabama
Power Company and Southern
Company Services, progressing to
Principal Engineer. EPRI lead
researcher in the NERC and DOE
sponsored GMD project which
included the development of
software tools and methods used to
analyze the impacts of a severe GMD
on the bulk electric system.
Developed and published a
geomagnetically induced current
(GIC) benchmark model that has
[email protected]
Executive
Director of
Infrastructure
Planning
Randy Horton,
Ph.D., P.E.
Vice Chair
Chief Engineer,
Transmission
Technical
Support
Southern
Company
Services
205.257.6352
jrhorton@
southernco.com
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Donald
Atkinson, P.E.
Georgia
Transmission
Corporation
Relay and
Control
Designer and
System
Protection
Engineer
Emanuel
Bernabeu,
Ph.D., P.E.
Lead Power
Engineer,
Special System
Studies
Dominion
Technical
Solutions, Inc
been used by commercial software
vendors and others to develop and
validate GIC models. Senior Member
of the IEEE and Member of CIGRE.
Chair of the IEEE Working Group on
Field Measured Overvoltages,
Secretary of IEEE Std. 519
(harmonics), Co-Chair of the IEEE
GMD Task Force, Advisory Council
Member for EPRI’s Substations
Research Program.
770.270.7178
Relay and Control Designer and
System Protection engineer.
donald.atkinson@ Responsible for relay designs,
gatrans.com
calculating relay settings, conducting
system planning studies, event
analyses, creating relay standards,
and writing transmission substation
operating instructions. BS in
Electrical Engineering (power
systems).
804-257-4017
Lead power engineer for special
system studies at Dominion. Member
emanuel.e.
of the GMD Task Force Equipment
bernabeu@
Modeling team. Responsible for
dom.com
Dominion’s GMD risk assessment and
mitigation strategy with extensive
experience regarding modeling,
planning, situational awareness, and
operational procedures for GMD.
Experience with GIC system
calculations, voltage stability
analysis, equipment vulnerability,
and mitigation planning. Senior
engineer for projects in transient
over-voltages (TOV), EMI, “Aurora”
cyber/physical attack, N-1-1
contingency analysis, black-start
stability assessment, Phasor
Measurements Units (PMUs)
applications, and root cause analysis
of protection relay misoperations.
Member of NERC’s Severe Impact
Resilience Task Force (SIRTF).
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Kenneth
Fleischer, P.E.
NextEra Energy
Nuclear Chief
Electrical / I&C
Engineer
Luis Marti,
Ph.D., PE
Manager,
Professional
Development
and Special
Studies
Hydro One
Networks
561.691.2456
Nuclear Chief Electrical Engineer
responsible for Electrical/I&C
kenneth.fleischer@ activities for two south Florida
fpl.com
nuclear sites and three nuclear sites
in upper North America. Member of
GMD Task Force. Experience with
solar mitigation activities during
Solar Cycle 23 while employed at
another nuclear power complex in
New Jersey that had developed
mitigation procedures from the 1989
solar events that damaged several
generator step up transformers.
Joined FPL in 2005, and took his solar
mitigation experience and applied it
to the northern nuclear sites in order
to protect their generator step up
transformers from extreme solar
geomagnetic disturbance events.
This included equipment,
transformer GIC rating
calculations/studies and detailed
GMD mitigation procedures.
416.345.5317
Manager, Professional development
and special studies, Hydro
luis.marti@
One. Leader of GMD Task Force
HydroOne.com
Equipment Modeling Team.
Research/study activities include the
development of models for the
family of EMTP programs, GIC
simulation, grounding, induction
coordination, EMF issues pertaining
to T&D networks, and
connection/operational issues
around the connection of renewable
generation in distribution networks.
Participated in a number of Canadian
and international technical
organizations such as CSA (Canadian
Standards Association, IEEE, and
CIGRE). Adjunct professor at the
universities of Western Ontario and
Ryerson.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Antti Pulkkinen,
Ph.D.
NASA Goddard
Space Flight
Center
Qun Qiu,
Ph.D., P.E.
American
Electric Power
614.552.1182
[email protected]
Principal
Engineer Transmission
Protection and
Control
Engineering
Director of Space Weather Research
Center (SWRC). Leader of GMD Task
Force Space Weather Science team
developing reference storm
scenarios. Published 1-in-100 year
storm scenarios used in the 2012
GMD Interim Report and presented
at various space weather technical
conferences. PhD and postdoctoral
research involved studies of ground
effects of space weather and
complex nonlinear dynamics of the
magnetosphere-ionosphere system.
Leads and participates in numerous
space weather-related projects
where scientists have been in close
collaboration with industrial
partners. In many of these projects,
his work has involved general
geomagnetic induction modeling and
modeling of space weather effects on
pipelines and power transmission
systems. Recently been leading the
development of operational space
weather forecasting activity at NASA
GSFC. Worked as an Associate
Director of Institute for Astrophysics
and Computational Sciences and as
an Associate Professor at The
Catholic University of America (CUA)
where he launched a new Space
Sciences and Space Weather
program crafted to educate next
generation scientists and space
weather operators.
Principal Engineer – Transmission
Protection & Control Engineering.
Member of GMD Task Force
Equipment Modeling team. Leading a
team in implementing company-wide
GIC/Harmonics monitoring system
and developing GMD mitigation
efforts. Keynote presenter at
February GMDTF in-person meeting,
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
and recent speaker on GMD at CIGRE
Grid of the Future Symposium, North
American Transmission Forum Board
Meeting, Southwest Power Pool
(SPP) Compliance Forum. Coauthored several papers on GMD
monitoring, GIC modeling and
simulations. Member of CIGRE;
senior member of IEEE.
Mark Olson
Standards
Developer
NERC
404.446.9760
mark.olson@
nerc.net
Standards Developer at NERC since
October 2012. Previously a career
officer in the U.S. Navy where he
served in various positions related to
the operations and management of
surface ships and naval personnel.
Master's degree in electrical
engineering from the Naval
Postgraduate School and a bachelor’s
degree from the U.S. Naval Academy.
20131114-5150 FERC PDF (Unofficial) 11/14/2013 3:55:57 PM
Document Content(s)
Petition for Approval of EOP-010-1 FINAL.PDF..........................1-19
Exhibit A_EOP-010-1-RBS_clean.PDF.....................................20-27
Exhibit B_Implementation_clean.PDF....................................28-30
Exhibit C Order No 672.PDF............................................31-38
Exhibit D_ApplicableNetwork_clean.PDF.................................39-49
Exhibit E_EntityApplicability_whitepaper_clean.PDF....................50-54
Exhibit F_VRF-VSL_EOP-010-1.PDF.......................................55-71
Exhibit G_GMD_directivesMap_Oct172013.PDF.............................72-74
Exhibit H_Summay Development History.PDF..............................75-495
Exhibit I _Roster_filling_Oct25.PDF...................................496-501
| File Type | application/pdf |
| File Title | Microsoft Word - Petition for Approval of EOP-010-1 Geomagnetic Disturbance Mitigation_FINAL |
| File Modified | 2013-11-14 |
| File Created | 2013-11-14 |