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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ______________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED EMERGENCY OPERATIONS RELIABILITY
STANDARDS
Nina H. Jenkins-Johnston
Senior Counsel
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-9650
nina.johnston@nerc.net
Counsel for the North American Electric
Reliability Corporation
March 27, 2017
TABLE OF CONTENTS
I. EXECUTIVE SUMMARY .................................................................................................... 2
II. NOTICES AND COMMUNICATIONS ................................................................................ 3
III. BACKGROUND .................................................................................................................... 3
A.
Regulatory Framework ..................................................................................................... 3
B.
NERC Reliability Standards Development Procedure ..................................................... 4
C.
Development of the Proposed Reliability Standards........................................................ 5
IV. JUSTIFICATION FOR APPROVAL..................................................................................... 6
A.
Proposed Reliability Standard EOP-004-4 – Event Reporting ........................................ 7
1.
Requirement-by-Requirement Justification .................................................................. 7
a. EOP-004-4, Proposed Requirement R2 ........................................................................ 7
b. EOP-004-4, Proposed Retirement of Requirement R3 ................................................. 8
c. EOP-004 - Attachment 1: Reportable Events ............................................................... 9
d. EOP-004 - Attachment 2: Event Reporting Form ...................................................... 23
B.
Proposed Reliability Standard EOP-005-3 – System Restoration from Blackstart
Resources .................................................................................................................................. 23
1.
Requirement-by-Requirement Justification ................................................................ 24
a. EOP-005-3, Proposed Requirement R1 ...................................................................... 24
b. EOP-005-3, Proposed Requirement R2 ...................................................................... 26
c. EOP-005-3, Proposed Requirement R3 ...................................................................... 27
d. EOP-005-3, Proposed Requirement R4 ...................................................................... 27
e. EOP-005-3, Proposed Requirement R5 ...................................................................... 30
f. EOP-005-3, Proposed Requirement R6 ...................................................................... 30
g. EOP-005-2, Requirement R7...................................................................................... 31
h. EOP-005-2, Requirement R8...................................................................................... 31
i. EOP-005-3, Proposed Requirement R8 ...................................................................... 32
j. EOP-005-3, Proposed Requirement R9 ...................................................................... 33
C.
Proposed Reliability Standards EOP-006 – 3 – System Restoration Coordination ....... 34
1.
Requirement-by-Requirement Justification................................................................ 34
a. EOP-006-3, Proposed Requirement R1 ...................................................................... 34
b. EOP-006-3, Proposed Requirement R4 ...................................................................... 36
c. EOP-006-3, Proposed Requirement R5 ...................................................................... 36
d. EOP-006-3, Proposed Requirement R6 ...................................................................... 37
e. EOP-006-2, Requirements R7 and R8........................................................................ 37
f. EOP-006-3, Proposed Requirement R7 ...................................................................... 37
g. EOP-006-3, Proposed Requirement R8 ...................................................................... 38
D.
Proposed Reliability Standard EOP-008-2 – Loss of Control Center Functionality...... 38
1.
Requirement-by-Requirement Justification................................................................ 39
a. EOP-008-2, Proposed Requirement R1 ...................................................................... 39
E.
Enforceability of the Proposed Reliability Standards .................................................... 40
V. EFFECTIVE DATE .............................................................................................................. 41
VI. CONCLUSION ..................................................................................................................... 41
i
Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
Exhibit F
Exhibit G
Exhibit H
Proposed Reliability Standards
Exhibit A-1 Proposed Reliability Standard EOP-004-4
Exhibit A-2 Proposed Reliability Standard EOP-005-3
Exhibit A-3 Proposed Reliability Standard EOP-006-3
Exhibit A-4 Proposed Reliability Standard EOP-008-2
Implementation Plans
Exhibit B-1 Implementation Plan for Proposed Reliability Standard EOP-004-4
Exhibit B-2 Implementation Plan for Proposed Reliability Standards EOP-0053, EOP-006-3 and EOP-008-2
Order No. 672 Criteria
Mapping Documents
Exhibit D-1 Mapping Document for Proposed Reliability Standard EOP-004-4
Exhibit D-2 Mapping Document for Proposed Reliability Standards EOP-0053, EOP-006-3 and EOP-008-2
Analysis of Violation Risk Factors and Violation Severity Levels
Exhibit E-1 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard EOP-004-4
Exhibit E-2 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard EOP-005-3
Exhibit E-3 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard EOP-006-3
Exhibit E-4 Analysis of Violation Risk Factors and Violation Severity Levels
for Reliability Standard EOP-008-2
Consideration of Issues and Directives
Summary of Development History and Complete Record of Development
Standards Drafting Team Roster
ii
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 EMERGENCY OPERATIONS RELIABILITY
STANDARDS
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 2 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission approval
proposed Emergency Operations (“EOP”) Reliability Standards EOP-004-4 (Event Reporting),
EOP-005-3 (System Restoration from Blackstart Resources), EOP-006-3 (System Restoration
Coordination), and EOP-008-2 (Loss of Control Center Functionality). NERC requests that the
Commission approve the proposed Reliability Standards (Exhibit A) as just, reasonable, not
unduly discriminatory or preferential, and in the public interest. NERC also proposes that the
Commission approve: (i) the associated Implementation Plans (Exhibit B); (ii) the Violation Risk
Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibit E); and (iii) the retirement of
the currently-effective Reliability Standards EOP-004-3, EOP-005-2, EOP-006-2, and EOP-0081, upon Commission approval of the proposed Reliability Standards.
1
16 U.S.C. § 824o (2012).
2
18 C.F.R. § 39.5 (2016).
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).
1
As required by Section 39.5(a) 4 of the Commission’s regulations, this petition presents the
technical basis and purpose of the proposed Reliability Standards, a demonstration that the
proposed Reliability Standards meet the criteria identified by the Commission in Order No. 672 5
(Exhibit C), and a summary of the standard development proceedings (Exhibit G). The NERC
Board of Trustees (“Board”) adopted the proposed EOP Reliability Standards on February 9, 2017.
I.
EXECUTIVE SUMMARY
The primary objectives of the proposed EOP Reliability Standards are as follows:
(1) to provide accurate reporting of events to NERC’s Event Analysis group to analyze the
impact on the reliability of the Bulk Electric System (“BES”) (EOP-004-4);
(2) to delineate the roles and responsibilities of entities that support System restoration
from Blackstart Resources which generate power without the support of the grid (EOP005-3);
(3) to clarify the procedures and coordination requirements for Reliability Coordinator
personnel to execute System restoration processes (EOP-006-3); and,
(4) to refine the required elements of an Operating Plan used to continue reliable operations
of the BES in the event that primary control functionality is lost (EOP-008-2).
The proposed revisions incorporate several recommendations of the Project 2015-02
Emergency Operations Periodic Review Team as well as the Independent Experts Review Panel
(“Panel”). 6 They also reflect collaboration with the Department of Energy (“DOE”) to eliminate
4
18 C.F.R. § 39.5(a)(2016).
5
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”), 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).
6
NERC retained five industry experts (“Panel”) to independently review the content and quality of the
NERC Reliability Standards, including identification of potential BPS risks that were not adequately mitigated. See
Standards Independent Experts Review Project: An Independent Review by Industry Experts, available at
http://www.nerc.com/pa/Stand/Resources/Documents/Standards_Independent_Experts_Review_Project_Report.pdf.
2
either inaccurate or duplicate reporting of events identified in DOE’s Electric Emergency Incident
and Disturbance Report (“OE-417”) as well as in Attachment 1 to NERC’s Reliability Standard
EOP-004. The proposed standards substantially improve upon the existing standards by enhancing
the requirements for Emergency operations, including the communication and coordination
amongst reporting entities.
For reasons discussed herein, NERC requests that the Commission approve the proposed
Reliability Standards and the proposed retirement of Reliability Standards EOP-004-3, EOP-0052, EOP-006-2 and EOP-008-1 as 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: 7
Nina Jenkins-Johnston
Senior Counsel
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-9650
nina.johnston@nerc.net
III.
Howard Gugel
Director of Standards
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
howard.gugel@nerc.net
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 8 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the nation’s Bulk-Power System,
7
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 (2012), to allow the inclusion
of more than two persons on the service list in this proceeding.
8
16 U.S.C. § 824o (2012).
3
and with the duties of certifying an Electric Reliability Organization (ERO) that would be charged
with developing and enforcing mandatory Reliability Standards, subject to Commission approval.
Section 215(b)(1) of the FPA states that all users, owners, and operators of the Bulk-Power System
in the United States will be subject to Commission-approved Reliability Standards. 9 Section
215(d)(5) of the FPA authorizes the Commission to order the ERO to submit a new or modified
Reliability Standard. 10 Section 39.5(a) of the Commission’s regulations requires the ERO to file
with the Commission for its approval each Reliability Standard that the ERO proposes should
become mandatory and enforceable in the United States, and each modification to a Reliability
Standard that the ERO proposes should be made effective. 11
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 FPA 12 and Section 39.5(c) 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. 13
B.
NERC Reliability Standards Development Procedure
The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 14 NERC
9
Id. at § 824(b)(1).
10
Id. at § 824o(d)(5).
11
18 C.F.R. § 39.5(a)(2016).
12
16 U.S.C. § 824o(d)(2).
13
18 C.F.R. § 39.5(c)(1)(2016).
14
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
4
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 15 In its order
certifying NERC as the Commission’s ERO, the Commission found that NERC’s proposed rules
provide for reasonable notice and opportunity for public comment, due process, openness, and a
balance of interests in developing Reliability Standards, 16 and thus satisfy certain of the criteria
for approving Reliability Standards. 17 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 is required to
approve a Reliability Standard before the Reliability Standard is submitted to the Commission for
approval.
C.
Development of the Proposed Reliability Standards
As further described in Exhibit G hereto, the proposed Emergency Preparedness and
Operations (“EOP”) group of Reliability Standards (EOP-004-4, EOP-005-3, EOP-006-3, and
EOP-008-2) were developed to implement the revisions and retirements recommended by the EOP
Standard Drafting Team from Project 2015-02 – Periodic Review of Emergency Operations (“EOP
SDT”). In addition, the proposed EOP Reliability Standards are intended to (1) streamline the
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.”).
15
The NERC Rules of Procedure, available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual, available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
16
N. Am. Elec. Reliability Corp, 116 FERC ¶ 61,062, at P 250.
17
Order No. 672, at PP 268, 270.
5
standards; (2) apply Paragraph 81 criteria; 18 while making the standards more results-based; and
(3) address the Commission’s concern articulated in Order No. 749 regarding system restoration
training. 19
For a summary of the development history in Project 2015-08 and the complete record of
development, see Exhibit G.
IV.
JUSTIFICATION FOR APPROVAL
As discussed in detail in Exhibit C, the proposed Reliability Standards satisfy the
Commission’s criteria in Order No. 672 and are just, reasonable, not unduly discriminatory or
preferential, and in the public interest.
Below, NERC (1) describes the reliability purpose of each proposed standard, (2) provides
a justification for the proposed revisions to each Reliability Standard, and, (3) discusses the
enforceability of the proposed standards.
18
See North American Electric Reliability Corp., 138 FERC ¶ 61,193, at P 81 (March 2012 Order), order on
reh’g and clarification, 139 FERC ¶ 61,168 (2012).
19
Order No. 749, System Restoration Reliability Standards, 134 FERC ¶ 61,215, 76 Fed. Reg. 16277 (2011)
(“Order No. 749”) at PP 18, 24:
Requirement R11 of EOP-005-2 requires that a minimum of two hours of system restoration training be
provided every two years to field switching personnel performing “unique tasks” associated with the
transmission operator’s restoration plan. In the NOPR, the Commission expressed concern that the
applicable entities may not understand what the term “unique tasks” means. We requested comment on
what is intended by that term and on whether guidance should be provided to the transmission operators,
transmission owners, and distribution providers who are responsible for providing training. In addition, the
NOPR sought comment as to whether the unique tasks should be identified in each transmission operator’s
restoration plan.
...
Once the Standard is effective, if industry determines that ambiguity with the term arises, it would be
appropriate for NERC to consider its proposal to develop a guideline to aid entities in their compliance
obligations.
6
A.
Proposed Reliability Standard EOP-004-4 – Event Reporting
The purpose of Reliability Standard EOP-004-4 is to improve the reliability of the BES by
requiring the reporting of events by Responsible Entities. The reportable events under this
standard are collected and used for operations planning and operational assessments. Specifically,
these reportable events are used to examine the underlying causes of events, track subsequent
corrective action to prevent recurrence of such events, and develop lessons learned for industry.
The reportable events under this standard are not intended to address issues that arise in Real-time
operations which often require action by Responsible Entities within one hour or less to preserve
the reliability of the BES.
The proposed changes to this standard are designed to (1) eliminate redundant reporting of
a single event by multiple entities, (2) assign reporting to appropriate entities, (3) clarify the
threshold reporting for a given event; and, (4) where appropriate, align the reportable events and
thresholds identified in Attachments 1 and 2 of the standard with the DOE’s OE-417. The
proposed changes improve the quality of information received by the ERO as well as the quality
of analysis that the ERO produces from this information to assess the greatest risk to the BES.
1.
Requirement-by-Requirement Justification
a.
EOP-004-4, Proposed Requirement R2
In Requirement R2, NERC proposes to expressly reference Attachment 1. This reference
was previously absent from Requirement R2 and improves the requirement by identifying the
universe of events reportable under this standard. NERC also streamlines the timing language for
event reporting. NERC proposes that Responsible Entities must submit reports “by the later of”
either 24 hours after recognizing that a reportable event has occurred or “by the end of the
Responsible Entity’s next business day.” The EOP SDT found that referencing “business day”
eliminates the need for the requirement to further indicate that reporting is not expected on the
7
weekend and holidays. The EOP SDT denotes the end of the business day as “4 p.m. local time”
to eliminate possible confusion regarding when the reporting obligation ends on a given business
day. None of these changes, as reproduced below, affect the frequency or pace at which EOP-004
reports are submitted.
R2.
Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the
entities specified per their event reporting Operating Plan within by the later of 24 hours
of recognition of meeting an event type threshold for reporting or by the end of the
Responsible Entity’s next business day if the event occurs on a weekend (which is
recognized to be 4 PM (4 p.m. local time on Friday to 8 AM Monday local time).will be
considered the end of the business day). [Violation Risk Factor: Medium] [Time Horizon:
Operations Assessment]
b.
EOP-004-4, Proposed Retirement of Requirement R3
Under the currently-effective Requirement R3, Responsible Entities must validate contact
information in their Operating Plans each calendar year. NERC proposes to retire Requirement
R3 under Criterion B1 as an administrative task not warranting a requirement. 20 The process of
validating contact lists is a good business practice of many utilities, but not a reliability priority.
Furthermore, this proposed retirement of Requirement R3 is also consistent with the Panel’s
recommendation and rationale.
20
Paragraph 81 Criteria B (Identifying Criteria) - B1. Administrative:
The Reliability Standard requirement requires responsible entities to perform a function that is administrative in
nature, does not support reliability and is needlessly burdensome. This criterion is designed to identify requirements
that can be retired or modified with little effect on reliability and whose retirement or modification will result in an
increase in the efficiency of the ERO compliance program. Administrative functions may include a task that is related
to developing procedures or plans, such as establishing communication contacts. Thus, for certain requirements,
Criterion B1 is closely related to Criteria B2, B3 and B4. Strictly administrative functions do not inherently negatively
impact reliability directly and, where possible, should be eliminated or modified for purposes of efficiency and to
allow the ERO and entities to appropriately allocate resources.
8
c.
EOP-004 - Attachment 1: Reportable Events
In Attachment 1 NERC identifies the types and thresholds of reportable events that have
the potential to impact the reliability of the BES. To report events to NERC, Responsible Entities
in the U.S. must submit Attachment 2 to EOP-004, which incorporates the event types in
Attachment 1. To the extent that DOE’s OE-417 reflects similar event types and thresholds as
Attachment 2, Responsible Entities in the U.S. may submit OE-417 in lieu of Attachment 2.
The currently-effective event types and thresholds reflected in Attachments 1 and 2 and
OE-417 are not all aligned, resulting in a level of uncertainty as to whether an event is reportable.
Some event types overlap (e.g., “system wide voltage reduction of 3% or more” in EOP-004 and
“system-wide voltage reductions of 3 percent or more” in OE-417). In other event types, the
degree of overlap is ambiguous (e.g., “physical threat to its BES control center.. .which has the
potential to degrade the normal operation of the control center or suspicious device or activity at a
BES control center” in EOP-004 compared to “physical attack that could potentially impact
electric power system adequacy or reliability; or vandalism which targets components of any
security systems” in OE-417). Certain event types exist exclusively in EOP-004 (e.g., “complete
loss of off-site power affecting a nuclear generating station per the Nuclear Plant Interface
Requirement”). In cases where a Responsible Entity is unsure whether two event types are aligned
between the two forms, that entity could duplicate efforts and submit both forms for a single event.
Alternatively, a Responsible Entity may fail to report a reportable event due to ambiguity in the
description of an event type in either form.
The accurate reporting of disturbances and events is essential for the ERO and
governmental authorities, such as DOE, to provide industry with meaningful trend and root causes
analyses. The EOP SDT identified the potential for efficiency in clarifying event types and
9
thresholds and aligning reporting requirements between EOP-004 and OE-417. 21 The proposed
revisions to Attachment 1 represent an improvement in the identification and reporting of such
events.
NERC’s proposed revisions to Attachment 1 aim to accomplish the following:
(1) assign reporting to responsible entities with relevant operating responsibilities;
(2) align the event types between Attachment 1 and OE-417 as much as possible to
eliminate redundancies in reporting of a single event thereby enhancing the efficiency of
event reporting; and,
(3) establish appropriate thresholds for triggering events that pose the greatest reliability
risk to the BES.
Below, NERC outlines the proposed revisions to each event type and its respective
threshold.
i.
Damage or Destruction to Facilities
Responsible Entities that experience damage or destruction to a Facility resulting from
“actual or suspected intentional human action” are required to submit a report to NERC. NERC
proposes three changes to this event type. First, NERC proposes to remove Balancing Authorities
as Responsible Entities, but leaves Transmission Owners, Transmission Operators, Generation
Owners, Generation Operators, and Distribution Providers as appropriate Responsible Entities.
The EOP SDT found that Facility owners and operators are best suited to identify any damage or
destruction to their Facilities and therefore should bear the reporting responsibility. Examples of
Facilities include a Transmission line, a generator, a shunt compensation device or a transformer.
Balancing Authorities do not own the relevant Facilities. To further reflect the importance of
21
The ERO has an Event Analysis Program (“EAP”) which evaluates the reports submitted pursuant to EOP004 and OE-417. Such reports may trigger further scrutiny by EAP personnel. EAP personnel may request that
more data about a given event.
10
ownership or operations of a Facility to identification of such an event, NERC also proposes to
change the event type from “Damage or destruction of a Facility” to “Damage or destruction of its
Facility.” Finally, NERC clarifies in the event threshold that theft from its Facility should not be
reported as damage or destruction unless it degrades normal operation of its Facility. Copper theft
from the infrastructure of Facilities is a frequent occurrence in the industry; however, the EOP
SDT concluded that the reporting obligation for this event type should focus on those that threaten
the operation of the Facility. Acts of theft were previously reported under the “physical threat”
event type and NERC proposes to move it to the “damage or destruction” event type because it
involves the infrastructure of a Facility.
ii.
Physical Threats to Facilities
Responsible Entities that experience physical threats to a Facility, including suspicious
devices or activities at a Facility, but excluding weather and natural disaster, are required to submit
an event report. NERC proposes three changes to this event type. NERC again proposes that
Facility owners and operators are best suited to identify any such threat and therefore should bear
the reporting responsibility. As a functional entity, Balancing Authorities do not own or operate a
Facility; therefore, they are removed as a Responsible Entity. Second, to reflect the importance of
ownership or operation of a Facility, NERC proposes to change the event type to “Physical threats
to its Facility.” Finally, NERC proposes to modify the statement “Do not report theft unless it
degrades normal operation of a Facility” and to modify it to read as “It is not necessary to report
theft unless it degrades normal operation of its Facility.” NERC also moves this modified language
to the “Damage or Destruction of its Facility” threshold for reporting. An actual act of theft to a
Facility more closely relates to damage or destruction of a Facility rather than a physical threat.
11
iii.
Physical Threats to BES Control Center
Consistent with other event types, NERC proposes to change the physical threat event type
and threshold to reflect the importance of ownership of a Facility. NERC proposes to change the
event type to “Physical threats to its BES control center” and the threshold to “Suspicious device
or activity at its BES control center.”
iv.
Public Appeal for Load Reduction
NERC Reliability Standard EOP-011-1 (Emergency Operations) ensures that all
Reliability Coordinators understand potential and actual Energy Emergencies in the
Interconnection. Energy Emergency Alert Level 2 (EEA-2) involves load management procedures
such as public appeals to reduce demand, interrupting firm load commitments, and voltage
reduction. Public appeals for load reduction are conducted when load is expected to exceed
available generation. Such appeals often occur on extreme weather days where a local utility asks
customers to reduce usage of electricity during certain hours of the day. These appeals would not
include load management for economic reasons.
NERC proposes two substantive changes to the “public appeal for load reduction” event
type in EOP-004-4 to report instances where an entity initiates a public appeal for load reduction.
First, NERC replaces “initiating entity” with “Balancing Authority” as the entity responsible for
reporting this event.
Pursuant to EOP-011-1 (Emergency Operations), it is the Balancing
Authority that develops, maintains and implements Reliability Coordinator-reviewed Operating
Plans to mitigate Capacity Emergencies and Energy Emergencies within its Balancing Authority
Area. Balancing Authorities must include processes to prepare for and mitigate Emergencies in
these Operating Plans. Furthermore, the Balancing Authority, pursuant to Reliability Standard
EOP-011-1, Requirement R2, Part 2.2.2, is responsible for requesting the Reliability Coordinator
12
to declare an Energy Emergency Alert. Second, NERC clarifies that the threshold for such a load
reduction event is when the requested reduction is required to maintain the continuity of the BES.
This clarifying language aligns with similar language in DOE’s OE-417 form which includes the
event type “Public appeal to reduce the use of electricity for purposes of maintaining the continuity
of the electric power system.”
v.
Voltage Reduction
Voltage reduction is a load management procedure in which the Transmission Operator
requests or directs distribution operators to decrease voltage in the distribution portion of the
System to minimize the likelihood of service interruptions. This lower voltage in turn reduces the
load on home devices. For purposes of reporting voltage reduction under EOP-004-4, NERC
replaces the phrase “initiating entity” with “Transmission Operator” as the Transmission Operator
is in fact the entity that initiates voltage reduction and, in turn, should be responsible for reporting
the event.
vi.
Load Shedding
NERC proposes to combine two event types – “BES Emergency requiring manual firm
load shedding” and “BES Emergency resulting in automatic firm load shedding” into a single event
type – “Firm load shedding resulting from a BES Emergency.” This change streamlines the list of
events in Attachment 1. In the reporting threshold, NERC indicates that the 100 MWs threshold
can be attributed to either manual or automatic load shedding.
NERC also removes the
requirement that the automatic load shedding be attributed to “undervoltage or underfrequency
load shedding schemes, or [Remedial Action Schemes].” These schemes are automatic systems
designed to decrease load when either the voltage or frequency of a System reaches predetermined
low levels. The EOP SDT found that it was unnecessary to detail specific types of load shedding
13
schemes in the standard. As the name of a scheme may change and new load shedding practices
may be developed, NERC proposes to keep the language in the threshold broad and to eliminate
specific practice references to accommodate future changes in practice or nomenclature.
For both automatic and manual load shedding, NERC identifies the Responsible Entity as
the “initiating Reliability Coordinator, Balancing Authority or Transmission Operator.” Pursuant
to EOP-011-1 (Emergency Operations), Balancing Authorities and Transmission Operators must
develop, maintain and implement Reliability Coordinator-approved Operating Plans to mitigate
Capacity Emergencies, Energy Emergencies, and operating Emergencies in their respective areas.
These Operating Plans shall include provisions for operator-controlled manual Load shedding that
minimize the overlap with automatic Load shedding and are capable of being implemented in a
timeframe adequate for mitigating the Emergency. NERC recognizes that for a given event, a
single entity may be registered for all three functions or three separate entities may be registered
for each of these functions. It is the intent of the EOP SDT that in either scenario, only one report
is required.
Distribution Providers and Transmission Operators were previously listed as entities with
reporting responsibility for automatic firm load shedding. NERC proposes to remove Distribution
Providers and instead assign the reporting obligation to the “initiating Reliability Coordinator,
Balancing Authority or Transmission Operator” because these entities have the appropriate level
of visibility to make assessments of the condition of the System. Any one of these functions can
independently generate or issue an Operating Instruction to shed firm load, but the Distribution
Provider cannot do so. Reliability Standard TOP-001-3 (Transmission Operations), Requirements
R1 and R2 provide that each Transmission Operator and Balancing Authority shall act to maintain
the reliability of its Transmission Operator Area and Balancing Authority Area via its own actions
14
or by issuing Operating Instructions. Requirements R3 and R5 further provide that the Distribution
Provider shall comply with each Operating Instruction issued by its Transmission Operator (s) or
Balancing Authority, unless such action cannot be physically implemented or it would violate
safety, equipment, regulatory, or statutory requirements. Furthermore, the purpose of Reliability
Standard EOP-011-1 (Emergency Operations) is to address the effects of operating Emergencies
by ensuring each Transmission Operator and Balancing Authority has developed Operating Plans
to mitigate operating Emergencies, and that those plans are coordinated within a Reliability
Coordinator Areas. Requirements R1 and R2 apply to the Transmission Operator and Balancing
Authority, but not to the Distribution Provider.
vii.
Voltage Deviation
A voltage deviation is the difference, generally expressed as a percentage, between the
voltage at a given instant at a point in the system, and a reference voltage (i.e., nominal voltage, a
mean value of the operating voltage, or declared supply voltage). NERC proposes to clarify the
event type name and threshold. NERC references “BES Emergency” in the event type to align
with other event types in Attachment 1 that warrant an action to preserve the reliability of the BES,
not a localized event. In the event threshold, NERC clarifies the range of deviation that threatens
the reliability of the System. In the currently-effective standard, the identified range of “± 10%”
could be interpreted as not requiring an event report if the voltage deviates more than 10%.
Therefore, NERC proposes that the relevant deviations warranting a report are those high, positive
deviations that exceed or are equal to 10% of the nominal voltage.
15
viii.
IROL Violation
Under the currently-effective standard, Reliability Coordinators are required to report when
they are operating outside of their Interconnection Reliability Operating Limit (“IROL”).
Specifically, an IROL violation occurs when the Transmission Operator operates outside the IROL
for a specified time known as IROL Tv. An IROL is a System Operating Limit, 22 which if violated,
could lead to instability, uncontrolled separation, or Cascading outages that adversely impact the
reliability of the BES. NERC proposes to retire the IROL violation event type under EOP-004-4
because EOP-004 is not designed to be a Real-time tool. During development of proposed
Reliability Standard EOP-004-4, some stakeholders commented that the removal of the IROL
event type deprives NERC and the Regional Entities of immediate or contemporaneous knowledge
of a risk of a cascading outage, thereby preventing a Regional Entity from immediately identifying
the root cause and developing appropriate mitigation. The EOP SDT found that any Real-time
reporting to the ERO or the Regional Entities (i.e., contemporaneously with the Transmission
Operator’s notification of the IROL to the Reliability Coordinator) should be addressed in the TOP
Reliability Standards which deal with the Real-time operations time horizon. In contrast, proposed
EOP-004-4 is primarily a tool for trending analysis and development of lessons learned.
The EOP SDT found that Reliability Standard TOP-001-3 (Transmission Operations) is
the appropriate standard for reporting such events. The purpose of Reliability Standard TOP-0013 is to prevent instability, uncontrolled separation, or Cascading outages, in Real-time, that
adversely impact the reliability of an Interconnection by ensuring “prompt action to prevent or
mitigate such occurrences.” Specifically, Requirement R12 states that “[e]ach Transmission
22
A “System Operating Limit” or “SOL” is the value that satisfies the most limiting of the prescribed
operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.
16
Operator shall not operate outside any identified Interconnection Reliability Operating Limit
(IROL) for a continuous duration exceeding its associated Tv.” Requirement R2 of Reliability
Standard TOP-007-0 (Reporting SOL and IROL Violations) states that “[f]ollowing a Contingency
or other event that results in an IROL violation, the Transmission Operator shall return its
transmission system to within IROL as soon as possible, but not longer than 30 minutes.” Finally,
Requirement R3 of Reliability Standard IRO-009-2 (Reliability Coordinator Actions to Operate
within IROLs) states that “[e]ach Reliability Coordinator shall act or direct others to act so that the
magnitude and duration of an IROL exceedance is mitigated within the IROL’s Tv, as identified
in the Reliability Coordinator’s Real-time monitoring or Real-time Assessment.”
ix.
Loss of Firm Load
Under the currently-effective standard, Balancing Authorities, Transmission Operators and
Distribution Providers are required to report two types of incidents involving loss of firm load
lasting at least 15 minutes: (1) loss of firm load greater than or equal to 300 MWs for those entities
whose previous year’s demand was greater than or equal to 3,000 MWs, or, (2) loss of firm load
greater than or equal to 200 MWs for all other entities. NERC proposes to rename the event type
to include “resulting from a BES Emergency” to align with other event types in Attachment 1 that
use this language.
NERC also proposes three changes to the event threshold to capture reporting of loss of
firm load events that pose the greatest risk to the reliability of the BES. First, NERC specifies that
reporting must occur for “uncontrolled loss of firm load” to eliminate reporting of intentional acts
by operators choosing to shed load to maintain System stability. This language aligns with the
event type language in OE-417. Second, NERC underscores that the load loss specifications in
this event type pertain to “a single incident” and should be reported only once by either the
17
Balancing Authority, Transmission Operator, or Distribution Provider, not all three. Finally,
NERC notes that for entities that suffer uncontrolled loss of firm load equal to or exceeding 300
MWs, the threshold for reporting entities is the previous year’s “peak” demand ≥ 3,000 MWs. By
highlighting “peak” demand, the EOP SDT notes that this improves the quality of reports by
focusing on the period posing the greatest risk to reliability.
x.
Generation Loss
Under the currently-effective “Generation loss” event type, Balancing Authorities and
Generator Operators must report total generation loss occurring within one minute that is either
greater than or equal to 2,000 MWs (for entities in the Eastern or Western Interconnection) or
greater than or equal to 1,000 MWs (for entities in the ERCOT or Quebec Interconnection). NERC
proposes four changes to the generation loss event type.
First, NERC proposes to remove “Generator Operators” as a reporting entity to eliminate
redundant reporting with Balancing Authorities for this event type. The EOP SDT found that the
obligation to report generation loss should rest solely with the Balancing Authority which has a
broader view of the system. It is the role of the Balancing Authority to maintain the generationload-interchange balance within its entire Balancing Authority Area.
Second, NERC proposes to raise the reporting threshold for generation loss in the Quebec
Interconnection from 1,000 MWs to 2,000 MWs. Generation in the Québec Interconnection is 95
% hydraulic. For efficiency reasons, generation must operate within 80 % of its operating range;
therefore, there is a large spinning operating reserve available at all times. This large spinning
reserve aids in the recovery period following an event. Generation is often adjusted in a Balancing
Authority Area to maintain the Area Control Error or “ACE” around zero.
18
ACE is the
instantaneous difference between a Balancing Authority’s Net Actual Interchange and Net
Scheduled Interchange. In Quebec, the recorded average ACE recovery time for a 2,000 MWs
generation loss is 5 minutes which is three times faster than the required recovery time of 15
minutes pursuant to Reliability Standard BAL-002-1a, Requirement R4.2 (Disturbance Control
Performance). 23 Following a review of Under Frequency Load Shedding events since 2000
submitted by Hydro Quebec, the EOP SDT found that generation loss between 1,500 MWs and
2,000 MWs has not triggered the first stage threshold of the Under Frequency Load Shedding
(“UFLS”) scheme. The fact that no recent events have triggered activation of UFLS is significant.
Activation of UFLS represents the last automated reliability measure associated with a decline in
frequency needed to rebalance the System. UFLS is intended to be a safety net to prevent against
System collapse for severe contingencies. Finally, Quebec has set 2,000 MWs as the threshold for
generation loss that would warrant a deficient Balancing Authority to request its Reliability
Coordinator to declare an Energy Emergency Alert (“EEA”). EEAs are emergency procedures
implemented if unusually high electricity demand or an unexpected loss of generation. The EOP
SDT reviewed historical EEA Level 3 alerts for the last 14 years (2000 through 2014) and found
no EEA level 3 alerts have occurred during this period in the Quebec Interconnection. Under
Quebec’s contingency analysis to evaluate abnormal conditions in its electrical network, it has set
2,000 MWs as its loss of generation threshold in the first or primary contingency.
Third, NERC proposes to raise the generation loss reporting threshold for the ERCOT
Interconnection from 1,000 MWs to 1,400 MWs. NERC notes that this is a lower threshold than
the 2,000 MWs threshold for ERCOT pursuant to the ERO event analysis process. ERCOT
23
Reliability Standard BAL-002-1a is designed to help Balancing Authorities utilize Contingency Reserves to
balance resources and demand and return Interconnection frequency within defined limits following a Reportable
Disturbance.
19
maintains a mix of operating reserves to aid in the recovery period following an event affecting
ACE or frequency. This mix comprises of 50% Load Resources controlled by under-frequency
relays and 50% frequency responsive spinning reserves. ERCOT procures between 2,300 MWs
and 3,000 MWs of frequency response reserves for all operating hours in addition to procuring
additional regulation and non-spinning reserves.
The Load Resources are set to respond
automatically at 59.7 Hz to provide instantaneous frequency response. The EOP SDT also
identified the recorded average ACE recovery time for a 1,400 MWs loss as 10 minutes for the
period between December 2014 and November 2016, which is faster than the required 15 minutes
pursuant to BAL-002-1a, Requirement R4.2 (Disturbance Control Performance). ERCOT’s
frequency responsive reserves are set at a level to allow ERCOT to keep frequency above the
under-frequency limit up to ERCOT’s resource contingency protection criteria limit of 2,750
MWs. This limit, which is almost double the proposed threshold, is significant because it
represents the point at which frequency response should be adequate to avoid violating UFLS
settings. This limit is also based on the most severe double contingency in ERCOT. Finally, the
proposed 1,400 MWs threshold is below the currently-effective EEA level 1 alert, the lowest EEA
level in ERCOT, which is set at 2,300 MWs.
Finally, NERC proposes to clarify the scope of reportable generation loss. Specifically,
NERC notes that reportable generation loss covers that resulting from the removal from service
availability of a generating unit for emergency reasons and the condition of the unavailable
equipment due to unanticipated failure (i.e., Forced Outage). It is not intended to cover generation
loss associated with weather patterns or fuel supply unavailability for dispersed power producing
resources. The variable output of these sources is understood by the Reliability Coordinator,
Balancing Authority, and Transmission Operator entities. Balancing Authorities responsible for
20
balancing load and generation model these generation resources accounting for this inherent
variability.
xi.
Transmission Loss
Under the currently-effective standard, Transmission Operators must report unexpected
transmission loss within its area if the loss occurs (1) following a common disturbance, (2) in a
manner that is contrary to design or unintended, and (3) involving three of more BES Elements.
For this “transmission loss” event type, NERC proposes to replace “BES Elements” with “BES
Facilities” in the event threshold description to capture transmission loss events that pose the
greatest risk to the reliability of the BES. The EOP SDT found that an unexpected loss of three or
more BES Elements is too granular and captures three or more individual device or equipment
failures (i.e., circuit breakers, disconnects, capacitor banks, reactors, bus potential devices) that are
unlikely to cause a common disturbance. The EOP SDT determined that the focus should be on
Facilities that cease to provide a path for BES power flows. This is also consistent with the
approach taken in the ERO event analysis process.
xii.
Complete Loss of Communication
NERC proposes to change the “complete loss of voice communication capability” event
type to “complete loss of Interpersonal Communication and Alternative Interpersonal
Communication capability at its staffed BES control center” to account for the variety of media
used by operators today consistent with Reliability Standard COM-001-2 (Communications). The
purpose of COM-001-2 is to establish Interpersonal Communication capabilities necessary to
maintain reliability.
The communication capabilities used by Reliability Coordinators,
Transmission Operators and Balancing Authorities may not necessarily be using the same medium.
In Order No. 808, the Commission approved two new communication definitions that NERC
21
proposes to incorporate into this event type – “Interpersonal Communication” defined as “any
medium that allows two or more individuals to interact, consult, or exchange information,” and,
“Alternative Interpersonal Communication” defined as “any Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communication used for day-to-day operation.” 24 These expanded definitions of
Communication capture more than just voice communication capability and more closely align
with practices of the reporting entities.
NERC also proposes to specify that the loss of communication threshold pertains to the
reporting entities’ at its “staffed BES control centers.” The EOP SDT found that unless a control
center is staffed, the Responsible Entity could not be made aware of an issue. Since a greater
number of media are accommodated by the proposed changes, NERC does not expect to see any
decrease in reporting for this revised event.
xiii.
Complete Loss of Monitoring Capability
NERC proposes to amend and streamline the monitoring capability event type and
threshold as follows:
•
Event Type - “Complete loss of monitoring or control capability at its
staffed BES control center”
•
Threshold for Reporting - “Complete loss of monitoring or control
capability affecting a at its staffed BES control center for 30 continuous
minutes or more such that analysis capability (i.e., State Estimator or
Contingency Analysis) is rendered inoperable.”
24
Order No. 808, Communications Reliability Standards, 151 FERC ¶ 61,039, 80 Fed. Reg.22, 385 (2015) at
fn. 54; Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability
Standards COM-001-2 and COM-002-4, Docket No. RM14-13-000 (filed May 14, 2014) at 18.
22
NERC proposes that the addition of “control capability” in both the event type and
threshold adequately addresses the phrase “such that analysis capability (i.e., State Estimator or
Contingency Analysis) is rendered inoperable.” NERC also specifies that loss of this capability
pertains to reporting entities with “a staffed BES control center.” The EOP SDT found that unless
a control center is staffed, the Responsible Entity would not be aware of an issue.
d.
EOP-004 - Attachment 2: Event Reporting Form
NERC has collaborated with DOE to align the event types and reporting thresholds
between EOP-004 and DOE’s OE-417 report for U.S. entities. Under current practice, the ERO
will accept DOE’s OE-417 report in lieu of Attachment 2 to the extent a given event type and
threshold align. The proposed event type changes to Attachment 1, as discussed above, are also
reflected in Attachment 2. In addition, NERC clarifies in the instructions to Attachment 2 that
EOP-004-4, Requirement R1 requires submission of either Attachment 2 or the OE-417 report to
other applicable organizations outside of the ERO (i.e., the entity’s Regional Entity, company
personnel, the entity’s Reliability Coordinator, law enforcement or other Applicable Governmental
Authorities).
B.
Proposed Reliability Standard EOP-005-3 – System Restoration from
Blackstart Resources
The purpose of proposed Reliability Standard EOP-005-3 is to “[e]nsure plans, Facilities,
and personnel are prepared to enable System restoration from Blackstart Resources to ensure
reliability is maintained during restoration and priority is placed on restoring the Interconnection.”
Proposed Reliability Standard EOP-005-3 improves the existing version of the standard in three
ways:
23
(1) emphasizes the need for Transmission Operators to not only develop, but utilize
restoration plans relating to Blackstart Resources;
(2) streamlines the standard and retires redundant or administrative requirements; and
(3) clarifies requirements for revising and testing restoration plans.
Additionally, NERC proposes to retire existing Reliability Standard EOP-005-2, as
described in the Implementation Plan for EOP-005-3 (See Exhibit B-1) to ensure a seamless
transition to the newly revised standard.
1.
Requirement-by-Requirement Justification
a. EOP-005-3, Proposed Requirement R1
Requirement R1 has been revised as follows:
R1.
Each Transmission Operator shall have develop and implement a restoration plan approved
by its Reliability Coordinator. The restoration plan shall allow for restoring be
implemented to restore the Transmission Operator’s System following a Disturbance in
which one or more areas of the Bulk Electric System (BES) shuts down and the use of
Blackstart Resources is required to restore the shut down shutdown area to service to a
state whereby the choice of the next Load to be restored is not driven by the need to control
frequency or voltage regardless of whether the Blackstart Resource is located within the
Transmission Operator’s System. The restoration plan shall include: [Violation Risk Factor
= High] [Time Horizon = Operations Planning, Real-time Operations]
1.1
Strategies for sSystem restoration that are coordinated with the its Reliability
Coordinator’s high level strategy for restoring the Interconnection.
...
1.3
Procedures for restoring interconnections with other Transmission Operators under
the direction of the its Reliability Coordinator.
...
1.9
Operating Processes for transferring authority operations back to the Balancing
Authority in accordance with the its Reliability Coordinator’s criteria
NERC proposes the addition of “develop and implement” to replace “have” as well as the
addition of “be implemented to restore” to replace “allow for restoring” to emphasize the need for
24
the Transmission Operator to not only possess, but to utilize its restoration plan for Real-time
operations in the event of a Disturbance. The addition of the word “implement” requires the
addition of “Real-time Operations” to the Time Horizon of this requirement. The addition of
“implement” to Requirement R1 makes Requirement R7 redundant. Requirement R7 provides
that:
R7.
Following a Disturbance in which one or more areas of the BES shuts down and the use of
Blackstart Resources is required to restore the shut down area to service, each affected
Transmission Operator shall implement its restoration plan. If the restoration plan cannot
be executed as expected the Transmission Operator shall utilize its restoration strategies to
facilitate restoration.
As a result of this redundancy, NERC proposes to retire Requirement R7. This proposed
retirement is consistent with the recommendation of the Panel to retire Requirement R7 as
redundant with Requirement R1. In describing the use of Blackstart Resources to restore the
shutdown area, NERC proposes to delete the words “to service” in Requirement R1 as redundant
with the ensuing language calling for “restoration of a shutdown area to a state whereby the choice
of the next Load to be restored is not driven by the need to control frequency or voltage regardless
of whether the Blackstart Resource is located within the Transmission Operator’s System.”
With respect to Requirement R1, Parts 1.1, 1.3 and 1.9, NERC proposes to replace “the
Reliability Coordinator” with “its Reliability Coordinator” to clarify that strategies, procedures
and operating processes for restoring interconnections and System restoration require coordination
with the Reliability Coordinator in the footprint where the Transmission Operator is located.
With respect to Requirement R1, Part 1.9, NERC proposes to replace “authority” with
“operations” to clarify two points. First, the EOP SDT noted that while the Transmission Operator
is responsible for developing and implementing the restoration plan, the Transmission Operator
25
does not assume any authority from the Balancing Authority. During restoration, the Transmission
Operator dedicates its resources to rebuilding its System. Second, the requirement to include
operating processes in a restoration plan relates to the role of the Reliability Coordinator. During
restoration, the Reliability Coordinator maintains its wide area view of the System. The Reliability
Coordinator takes operational authority and gives different entities assigned tasks until they are
ready to resume normal operation. As restoration progresses, the Reliability Coordinator gradually
transfers operations back to the appropriate entities.
b.
EOP-005-3, Proposed Requirement R2
The EOP SDT replaces “implementation date” with “effective date” to clarify that the
“implementation date” refers to any given use of a plan. Therefore, a given plan could have several
implementation dates. “Effective date” more accurately represents the pertinent date when entities
identified in a restoration plan should have a copy of a restoration plan changing roles and tasks
for future implementation. Recognizing that the Reliability Coordinator has 30 days under EOP006 to render a decision on restoration plan revisions, Transmission Operators must determine the
appropriate effective date for their plans. They must take into account the potential for unknown
factors (i.e., weather, system operational needs) to affect the configurations in their plans and the
subsequent in-service dates.
Requirement R2 has been revised as follows:
R2.
Each Transmission Operator shall provide the entities identified in its approved restoration
plan with a description of any changes to their roles and specific tasks prior to the
implementation effective date of the plan. [Violation Risk Factor = Medium] [Time
Horizon = Operations Planning]
26
c.
EOP-005-3, Proposed Requirement R3
Requirement R3, Part 3.1, was retired by the Commission in Order No. 788. 25 NERC is
not proposing any further revisions to Requirement R3 in this petition.
d.
EOP-005-3, Proposed Requirement R4
In the Report on the FERC-NERC Regional Entity Joint Review of Restoration and
Recovery Plans (“Joint FERC-NERC Report”), 26 joint staff from NERC and FERC recommended
that NERC clarify when system changes trigger a requirement to update restoration plans. The
joint staff recommended that NERC examine:
[1] the kinds of events that may warrant an update to the system
restoration plan . . . taking into account the length of time the system
is affected (not just permanent or planned system modifications), as
well as [2] the overall objective of ensuring that restoration plans are
generally flexible enough so that system modifications can be
addressed without continuous updates. [Emphasis added]
With this guidance, NERC proposes two event types of restoration plan revisions
warranting submission to its Reliability Coordinator: (i) unplanned permanent BES modifications
and (ii) planned, permanent BES modifications. NERC also proposes that for the former,
Transmission Operators submit revised restoration plans within 90 calendar days after identifying
the modification. For the latter type, NERC proposes that Transmission Operators submit revised
restoration plans in time to meet its Reliability Coordinator’s approval timeframe per EOP-006,
which is no less than 30 calendar days after identifying the modification. Proposed Requirement
R4 provides as follows:
25
Order No. 788, Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards,
145 FERC ¶ 61,147, 78 Fed. Reg. 73424 (2013).
26
Report on the FERC-NERC-Regional Entity Joint Review of Restoration and Recovery Plans (“FERCNERC Joint Report”), (Mar. 20, 2017), available at https://www.ferc.gov/legal/staff-reports/2016/01-29-16-FERCNERC-Report.pdf.
27
R4.
Each Transmission Operator shall update submit its revised restoration plan to its
Reliability Coordinator for approval within 90 calendar days after identifying any
unplanned permanent System modifications, or prior to implementing a planned BES
modification, that would change the implementation of its restoration plan when the
revision would change its ability to implement its restoration plan as follows: [Violation
Risk Factor = Medium] [Time Horizon = Operations Planning]
4.1.
Each Transmission Operator shall submit its revised restoration plan to its
Reliability Coordinator for approval within the same Within 90 calendar day period days
after identifying any unplanned permanent BES modifications; and.
4.1.4.2. Prior to implementing a planned permanent BES modification subject to its
Reliability Coordinator approval requirements per EOP-006.
Detailed below is an additional discussion of the modifications in Requirement R4.
A. BES Modifications vs. System Modifications
The currently-effective standard references both “unplanned permanent System
modifications” and “planned BES modifications” as two event types requiring updates to a
restoration plan. NERC proposes the consistent use of “BES modifications” in lieu of “System
modifications.” The term “BES” was developed through the NERC Standards Development
Process and is included in the Glossary of Terms Used in NERC Reliability Standards. 27 The use
of the phrase “BES modifications” is intended to capture changes that affect the implementation
of a restoration plan. Administrative changes, such as element number changes and device
changes, are examples that would not have a significant impact on the implementation of a
restoration plan and that would not be considered BES modifications.
B. Duration of a BES Modification
NERC proposes that the “permanence” of BES modifications is an important threshold to
determine when to submit revisions to a restoration plan. In the FERC-NERC report, staff
27
Unless otherwise designated, capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary of Terms”), available at
http://www.nerc.com/files/glossary_of_terms.pdf.
28
encouraged NERC to examine the length of time the system is affected. NERC maintains that the
“permanence” of a BES modification is a relevant threshold, regardless of whether planned or
unplanned. Using the “permanence” of a BES modification as a threshold is necessary to avoid
updates due to temporary configurations required to support maintenance and construction. It also
underscores that Transmission Operators should only submit changes that substantively affect the
implementation of their restoration plans.
C. Timing of Updates to Restoration Plans
In the FERC-NERC Joint Report, staff recommended that NERC clarify when System
changes under Requirement R4 will trigger a requirement to update restoration plans. 28 In the
currently-effective standard, it is unclear whether the 90 calendar day timeframe for updating
restoration plans applies to both “unplanned permanent System modifications” and “planned BES
modifications.”
NERC proposes two different triggers for submitting restoration plans to
Reliability Coordinators for “unplanned permanent BES modifications” and for “planned
permanent BES modifications.” Unplanned permanent BES modifications should be submitted to
the Reliability Coordinator no more than 90 calendar days after identifying the need for an
unplanned, permanent BES modification. Planned, permanent BES modifications should be
submitted to the Reliability Coordinator in accordance with EOP-006 Requirement R5, Part5.1.
EOP-006 Requirement R5, Part 5.1 provides that the Reliability Coordinator shall approve or
disapprove a submitted restoration plan within 30 days of receipt. Therefore, planned, permanent
BES modifications should be submitted to the Reliability Coordinator no less than 30 calendar
days prior to implementation in order to afford the Reliability Coordinator the minimum required
28
FERC-NERC Joint Report at 37.
29
time to render a decision under EOP-006, Requirement 5, Part 5.1. Proposed Reliability Standard
EOP-005, Requirement 4, Parts 4.1 and 4.2, are revised as follows:
R4.
Each Transmission Operator shall submit its revised restoration plan to its Reliability
Coordinator for approval within the same 90 calendar day period , when the revision would
change its ability to implement its restoration plan, as follows: [Violation Risk Factor =
Medium] [Time Horizon = Operations Planning]
4.1
Within 90 calendar days after identifying any unplanned permanent BES
modifications.
4.2
Prior to implementing a planned permanent BES modification subject to its
Reliability Coordinator approval requirements per EOP-006.
e.
EOP-005-3, Proposed Requirement R5
Consistent with Requirement R2, “implementation date” was revised to “effective date.”
“Effective date” more accurately represents the pertinent date when entities identified in a
restoration plan should have a copy of a restoration plan changing roles and tasks for future
implementation. Recognizing that the Reliability Coordinator has 30 days under EOP-006 to
render a decision on restoration plan revisions, Transmission Operators must determine the
appropriate effective date for their plans. Requirement R5 has been revised as follows:
R5.
Each Transmission Operator shall have a copy of its latest Reliability Coordinator
approved restoration plan within its primary and backup control rooms so that it is available
to all of its System Operators prior to its implementation effective date.
f.
EOP-005-3, Proposed Requirement R6
NERC proposes to clarify the methodology and frequency of required testing of restoration
plans in Requirement R6, as follows:
R6.
Each Transmission Operator shall verify through analysis of actual events a combination
of steady state and dynamic simulations, or testing that its restoration plan accomplishes
its intended function. This shall be completed at least once every five years at a minimum.
Such analysis, simulations or testing shall verify. . .
30
Industry indicated that currently-effective Reliability Standard EOP-005-2 could be
misinterpreted to require Transmission Operators to validate every step of the restoration process
with both steady state and dynamic simulation. NERC, therefore, clarifies that a Transmission
Operator should perform a combination of steady state and dynamic simulations for the overall
restoration process. This testing should occur at least once every five years.
g.
EOP-005-2, Requirement R7
As discussed above, the proposed additional language, “develop and implement” added to
EOP-005-3, Requirement R1 is redundant with EOP-005-2, Requirement R7. Therefore, NERC
proposes to retire Requirement R7. This proposed retirement is consistent with a recommendation
of the Panel.
The flexibility allotted to Transmission Operators to “utilize. . .restoration strategies to
facilitate restoration” when “the restoration plan cannot be executed as expected” under
Requirement R7 is preserved in Requirement R1, Part 1.1. Under Requirement R1, Part 1.1,
restoration plans shall include “[s]trategies for System restoration that are coordinated with its
Reliability Coordinator’s high level strategy for restoring the Interconnection.” Transmission
Operators retain the ability to deviate from their restoration plans if they cannot be executed as
expected, so long as that approach is outlined in their strategies. The proposed deletion of
Requirement R7 is not intended to diminish Transmission Operators’ adaptive capability
throughout the course of restoration activities.
h.
EOP-005-2, Requirement R8
NERC proposes to retire currently-effective EOP-005-2, Requirement R8 because its
requirements are captured in proposed EOP-005-3, Requirement R1, Part 1.1 and existing IRO001-1.1 Requirement R3. Currently-effective Reliability Standard EOP-005-2, Requirement R8
31
calls for Transmission Operators to resynchronize, with the permission of the Reliability
Coordinator, along with neighboring Transmission Operators where Blackstart Resources are
required, to restore one or more areas of the BES shut down by a Disturbance. The EOP SDT
notes that this coordination with neighboring Transmission Operators under Requirement R8 is
still captured by Requirement R1, Part 1.1. Through this part, NERC mandates that Transmission
Operators implement restoration plans which include “[s]trategies for System restoration that are
coordinated with its Reliability Coordinator’s high level strategy for restoring the
Interconnection.” Even though Part 1.1 does not expressly call for such resynchronization, it is
well understood by industry that such a step is integral to restoration activities. This critical
restoration step helps to prevent against loss of load. The ability of the Reliability Coordinator to
authorize such coordination and synchronization with neighboring Transmission Operators is
captured by IRO-001-1.1, Requirement R3, which vests Reliability Coordinators with “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.”
i.
EOP-005-3, Proposed Requirement R8
Proposed Requirement R8 renumbers language from currently effective EOP-005-2,
Requirement R10 and NERC proposes the following additional revisions. NERC proposes to
delete language in the main body of proposed Requirement R8, as redundant language already
addressed by training topics listed in Parts 8.1 through 8.5. NERC also proposes a new training
topic for the Transmission Operator training program in Part 8.5. Specifically, NERC identifies a
need to train on coordination with Balancing Authorities, specifically the transition of Demand
32
and resource balance within the Balancing Authority’s Area. Proposed Requirement R8 is revised
as follows:
R10 R8.
Each Transmission Operator shall include within its operations training program,
annual System restoration training for its System Operators to assure the proper execution
of its restoration plan. This training program shall include training on the following:
[Violation Risk Factor = Medium] [Time Horizon = Operations Planning]
R10.18.1.
System restoration plan including coordination with the its Reliability
Coordinator and Generator Operators included in the restoration plan
R10.28.2.
Restoration priorities
R10.38.3.
Building of cranking paths
R10.48.4.
Synchronizing (re-energized sections of the System)
8.5.
Transition to Balancing Authority for Demand and resource balance within its area.
j.
EOP-005-3, Proposed Requirement R9
Proposed Requirement R9 renumbers language from currently-effective EOP-005-2,
Requirement R11 and includes no revisions. Proposed Requirement R9 requires that a minimum
of two hours of System restoration training be provided every two calendar years to field switching
personnel performing “unique tasks” associated with the Transmission Operator’s restoration plan
that are outside of their normal tasks. In Order No. 749, in which the Commission approved several
System Restoration Reliability Standards, the Commission stated that “[o]nce [EOP-005-2] is
effective, if industry determines that ambiguity with the term arises, it would be appropriate for
NERC to consider its proposal to develop a guideline to aid entities in their compliance
obligations.” 29 The EOP SDT evaluated the use of “unique tasks” and concluded that its ordinary
meaning, outside of everyday tasks conducted by switching personnel, is sufficient and does not
require further clarification. While NERC may consider developing guidance in the future if
29
Order No. 749 at P 24.
33
compliance concerns arise surrounding defining “unique tasks,” entities retain the discretion to
define “unique tasks.”
C.
Proposed Reliability Standards EOP-006 – 3 – System Restoration
Coordination
The purpose of proposed Reliability Standard EOP-006-3 is to establish how personnel
should prepare, execute, and coordinate System restoration processes to maintain reliability and to
restore the Interconnection. Proposed Reliability Standard EOP-006-3 improves upon the existing
version of the standard in three ways:
(1) emphasizes the need for Reliability Coordinators to not only develop, but utilize their
restoration plans;
(2) streamlines the standard and retires redundant or administrative requirements; and
(3) clarifies requirements around training and coordination of restoration plans amongst
Reliability Coordinators.
In addition, NERC also proposes to retire Reliability Standard EOP-006-2, as described in
the Implementation Plan for EOP-006-3 (See Exhibit B), to ensure a seamless transition to the
newly revised standard.
1.
Requirement-by-Requirement Justification
a. EOP-006-3, Proposed Requirement R1
NERC proposes a modification to Requirement R1 by replacing “have” with “develop and
implement” language to emphasize the need for the Reliability Coordinator to possess and utilize
its restoration plan for Real-time operations. The addition of the word “implement” requires the
addition of “Real-time Operations” to the Time Horizon of this requirement. NERC proposes to
delete Parts 1.2 through 1.4 from Reliability Standard EOP-006-2 as redundant with Reliability
34
Standard EOP-006-2, Part 1.5 (which is renumbered as Part 1.2 in proposed EOP-006-3) as shown
below:
R1.
Each Reliability Coordinator shall havedevelop and implement a Reliability Coordinator
Area restoration plan. The scope of the Reliability Coordinator’s restoration plan starts
when Blackstart Resources are utilized to re‐energize a shut downshutdown area of the
Bulk Electric System (BES), or separation has occurred between neighboring Reliability
Coordinators, or an energized island has been formed on the BES within the Reliability
Coordinator Area. The scope of the Reliability Coordinator’s restoration plan ends when
all of its Transmission Operators are interconnected and it its Reliability Coordinator Area
is connected to all of its neighboring Reliability Coordinator Areas. The restoration plan
shall include: [Violation Risk Factor = High] [Time Horizon = Operations Planning, Real‐
time Operations]
1.1. A description of the high‐level strategy to be employed during restoration events for
restoring the Interconnection, including minimum criteria for meeting the objectives of the
Reliability Coordinator’s restoration plan.
1.2. Operating Processes for restoring the Interconnection.
1.3. Descriptions of the elements of coordination between individual Transmission
Operator restoration plans.
1.4. Descriptions of the elements of coordination of restoration plans with neighboring
Reliability Coordinators.
1.5.1.2. Criteria and conditions for reestablishingre‐establishing interconnections with
other Transmission Operators within its Reliability Coordinator Area, with Transmission
Operators in other Reliability Coordinator Areas, and with other Reliability Coordinators.
1.6.1.3. Reporting requirements for the entities within the Reliability Coordinator Area
during a restoration event.
1.7.1.4. Criteria for sharing information regarding restoration with neighboring Reliability
Coordinators and with Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area.
1.8.1.5. Identification of the Reliability Coordinator as the primary contact for
disseminating information regarding restoration to neighboring Reliability Coordinators,
and to Transmission Operators, and Balancing Authorities within its Reliability
Coordinator Area.
1.9.1.6. Criteria for transferring operations and authority back to the Balancing Authority.
35
b.
EOP-006-3, Proposed Requirement R4
The EOP SDT found that an important step in resolving conflicts in the restoration plans
of neighboring Reliability Coordinator’s is for the reviewing Reliability Coordinator to provide
the neighboring Reliability Coordinator with notice of the conflict. NERC proposes to add this
notification requirement to Requirement R4. NERC also clarifies the timing for resolving conflicts
as starting after receipt of written notification of a conflict. Requirement R4, Part 4.1 is revised as
follows:
R4.
Each Reliability Coordinator shall review theirits neighboring Reliability Coordinator’s
restoration plans. and provide written notification of any conflicts discovered during that
review within 60 calendar days of receipt. [Violation Risk Factor = Medium] [Time
Horizon = Operations Planning]
4.1. If thea Reliability Coordinator finds conflicts between its restoration plans and any of
its neighbors, the conflicts shall be resolved within 30 calendar days of receipt of written
notification.
c.
EOP-006-3, Proposed Requirement R5
NERC proposes to clarify that the Reliability Coordinator must notify the Transmission
Operator of its decision approving or disapproving a revised restoration plan per Reliability
Standard EOP-005. Requirement R5, Part 5.1 is revised as follows:
R5. Each Reliability Coordinator shall review the restoration plans required by EOP-005 of the
Transmission Operators within its Reliability Coordinator Area. [Violation Risk Factor =
Medium] [Time Horizon = Operations Planning]
5.1.
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. The Reliability Coordinator shall approve provide notification to the
Transmission Operator of approval or disapproveal, with stated reasons, of the
Transmission Operator’s submitted restoration plan within 30 calendar days following the
receipt of the restoration plan from the Transmission Operator.
36
d.
EOP-006-3, Proposed Requirement R6
NERC replaces “implementation date” with “effective date” in Requirement R6 to clarify
that the “implementation date” refers to any given use of a plan. Therefore, a given plan could
have several implementation dates. “Effective date” more accurately represents the pertinent date
when entities identified in a restoration plan should have a copy of a restoration plan changing
roles and tasks for future implementation.
Requirement R6 is revised as follows:
R6.
Each Reliability Coordinator shall have a copy of its latest restoration plan and copies of
the latest approved restoration plan of each Transmission Operator in its Reliability
Coordinator Area within its primary and backup control rooms so that it is available to all
of its System Operators prior to the implementationeffective date. [Violation Risk Factor
= Lower] [Time Horizon = Operations Planning]
e.
EOP-006-2, Requirements R7 and R8
NERC proposes to retire Requirements R7 and R8 from currently-effective Reliability
Standard EOP-006-2. The EOP SDT agrees with the recommendation of the Panel to retire these
requirements as “a logical action that does not require a standard.” The pending definition of
“Reliability Coordinator” addresses all of the tasks included in Requirements R7 and R8.
Requirements R7 and R8 offer examples of implementation steps taken by Reliability
Coordinators and are subsumed by the proposed addition of “develop and implement” to
Requirement R1 in proposed EOP-006-3.
f.
EOP-006-3, Proposed Requirement R7
NERC notes that the language in currently-effective EOP-006-2, Requirement R9 is
renumbered as proposed EOP-006-3, Requirement R7 due to proposed retirements in this standard.
NERC proposes to delete the language “to assure the proper execution of its restoration plan” in
Requirement R7,to streamline the language in the standard as follows:
37
R97.
Each Reliability Coordinator shall include within its operations training program, annual
System restoration training for its System Operators to assure the proper execution of its
restoration plan. This training program shall address the following: [Violation Risk Factor
= Medium] [Time Horizon = Operations Planning]
R79.1. The coordination role of the Reliability Coordinator.; and
R79.2. Re-establishing the Interconnection.
g.
EOP-006-3, Proposed Requirement R8
NERC notes that the language in currently-effective EOP-006-2, Requirement R10 is
renumbered as proposed EOP-006-3, Requirement R8 due to proposed retirements in this standard.
NERC purposes clarifying language for proposed Requirement R8 for the frequency for
Transmission Operators and Generator Operators to participate in drills, exercises or simulations.
R10R8.Each Reliability Coordinator shall conduct two System restoration drills, exercises, or
simulations per calendar year, which shall include the Transmission Operators and
Generator Operators as dictated by the particular scope of the drill, exercise, or simulation
that is being conducted. [Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
R10.1R8.1. Each Reliability Coordinator shall request each Transmission Operator
identified in its restoration plan and each Generator Operator identified in the Transmission
Operators’ restoration plans to participate in a drill, exercise, or simulation at least once
every two calendar years.
D.
Proposed Reliability Standard EOP-008-2 – Loss of Control Center
Functionality
The purpose of proposed Reliability Standard EOP-008-2 is to “[e]nsure continued reliable
operations of the BES in the event that a control center becomes inoperable.” Proposed Reliability
Standard EOP-008-2 improves upon the existing Reliability Standard EOP-008-1 by clarifying the
required contents of an Operating Plan used by Reliability Coordinators, Balancing Authorities
and Transmission Operators. NERC proposes to retire currently-effective Reliability Standard
38
EOP-008-1 as described in the Implementation Plan for proposed EOP-008-2 (See Exhibit B) to
ensure a seamless transition to the newly revised proposed standard.
1. Requirement-by-Requirement Justification
a. EOP-008-2, Proposed Requirement R1
NERC proposes to eliminate any ambiguity regarding the contents of an Operating Plan
used by a Reliability Coordinator, Balancing Authority and Transmission Operator to maintain
reliability of the BES when a primary control center loses its functionality. In Requirement R1,
NERC proposes that the contents of an Operating Plan for backup functionality listed in Parts 1.1
– 1.6 represent an exhaustive list rather than a minimum threshold.
NERC also proposes to change several of the elements required in the Operating Plan for
backup functionality. For Part 1.1., NERC removes the timing requirement to restore primary
control center functionality due to the wide range of events that could render the primary control
center inoperable. The EOP SDT found that it would be difficult for entities to assess their own
compliance with this restoration requirement given this variable.
For Parts 1.2 and 1.6, NERC proposes that the list of elements required to support the
backup functionality be exhaustive rather than a minimum threshold list.
This provides
Responsible Entities with clear direction regarding the contents of their Operating Plans. NERC
amends two of these backup functionality elements.
First NERC replaces “Voice
communications” with “Interpersonal Communications” to account for the variety of media used
by operators, consistent with Reliability Standard COM-001-2.1 (Communications), which also
adopts the term “Interpersonal Communications.” “Interpersonal Communications” are defined
as any medium that allows two or more individuals to interact, consult, or exchange information.
This change is also consistent with the event type change in EOP-004-4.
39
Second, NERC replaces “Data communications” with “Data exchange capabilities.”
COM-001-2.1 addresses “Interpersonal Communication” which covers Voice communications,
but not “Data exchange capabilities.” The term “data exchange capabilities” relates to facilities
that directly exchange or transfer data. The Commission adopted the term in Order No. 817, which
approved revisions to the Transmission Operations and Interconnection Reliability Operations and
Coordination Reliability Standards. 30 In Reliability Standard TOP-001-3, Requirements R19 and
R20, NERC requires each Transmission Operator and Balancing Authority to have data exchange
capabilities with the entities from which it needs data in order to maintain reliability in its area.
The same Requirement applies to Reliability Coordinators with respect to their Balancing
Authorities and Transmission Operators pursuant to IRO-002-4, Requirement R1 (Reliability
Coordination – Monitoring and Analysis). These data exchange capabilities are required to
support the data specifications required in Reliability Standard TOP-003-3 (Operational Reliability
Data).
E.
Enforceability of the Proposed Reliability Standards
The proposed Reliability Standards include VRFs and VSLs. The VRFs and VSLs provide
guidance on the way that NERC will enforce the Requirements of the proposed Reliability
Standards. The VRFs and VSLs for the proposed Reliability Standards comport with NERC and
Commission guidelines related to their assignment. Exhibit E provides a detailed review of the
VRFs and VSLs, and the analysis of how the VRFs and VSLs were determined using these
guidelines.
30
Order No. 817, Transmission Operations Reliability Standards and Interconnection Reliability Operations
and Coordination Reliability Standards, 153 FERC ¶ 61,178, 80 Fed. Reg. 73,977. (2015).
40
The proposed Reliability Standards also include Measures that support each Requirement
by identifying what is required and how the ERO will enforce the requirement. These Measures
help ensure that the Requirements will be enforced in a clear, consistent, and non-preferential
manner and without prejudice to any party. 31
V.
EFFECTIVE DATE
NERC respectfully requests that the Commission approve proposed Reliability Standards
EOP-004-4, EOP-005-3, EOP-006-3, and EOP-008-2 to become effective as set forth in the
proposed Implementation Plans, provided in Exhibit B hereto. The proposed Implementation
Plans provide that the proposed Reliability Standard shall become effective on the first day of the
first calendar quarter that is 12 calendar months after the effective date of the Commission’s order
approving the proposed Reliability Standard, or as otherwise provided for by the Commission.
VI.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
31
•
the proposed Reliability Standards included in Exhibit A, effective as proposed herein;
•
the Implementation Plans included in Exhibit B; and
•
the retirement of currently-effective Reliability Standards EOP-004-3, EOP-005-2, EOP006-2, and EOP-008-1, effective as proposed herein.
Order No. 672 at P 327.
41
Respectfully submitted,
/s/ Nina H. Jenkins-Johnston
Nina H. Jenkins-Johnston
Senior Counsel
Shamai Elstein
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
nina.johnston@nerc.net
shamai.elstein@nerc.net
Counsel for the North American Electric
Reliability Corporation
March 27, 2017
42
| File Type | application/pdf |
| File Title | Project 2015-08 Emergency Operations |
| Author | Nina Johnston |
| File Modified | 2017-12-06 |
| File Created | 2017-03-27 |