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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket Nos.
___________
RM12-6-___
RM12-7-___
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF REVISIONS TO THE DEFINITION OF “BULK ELECTRIC
SYSTEM” AND REQUEST FOR EXPEDITED ACTION
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
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]
Counsel for the North American Electric
Reliability Corporation
December 13, 2013
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
A. Overview of the Elements of the BES Definition............................................................... 3
B. Summary of Proposed Revisions to the BES Definition .................................................... 4
C. Implementation and Request for Expedited Action ............................................................ 5
II. REQUEST FOR PRIVILEGED TREATMENT .................................................................... 6
III. NOTICES AND COMMUNICATIONS ................................................................................ 6
IV. BACKGROUND .................................................................................................................... 7
A. Regulatory Framework ....................................................................................................... 7
B. NERC Reliability Standards Development Process ........................................................... 8
C. Procedural Background....................................................................................................... 9
1.
Order No. 693 ............................................................................................................... 9
2.
Order Nos. 743 and 743-A ........................................................................................... 9
3.
Order Nos. 773 and 773-A ......................................................................................... 11
V. JUSTIFICATION FOR APPROVAL .................................................................................. 12
A. Discussion of Proposed Revisions to the Definition of “Bulk Electric System” .............. 12
1.
“Core” Definition ....................................................................................................... 12
2.
Inclusions .................................................................................................................... 13
a.
Inclusion I1 (Transformers) .................................................................................... 13
b.
Inclusion I2 (Generating Resources) ...................................................................... 14
c.
Inclusion I3 (Blackstart Resources) ........................................................................ 14
d.
Inclusion I4 (Dispersed Power Producing Resources)............................................ 15
e.
Inclusion I5 (Static or Dynamic Reactive Power Devices) .................................... 18
3.
Exclusions................................................................................................................... 19
a.
Exclusion E1 (Radial Systems) ............................................................................... 19
b.
Exclusion E2 (Behind the Meter Generation) ......................................................... 26
c.
Exclusion E3 (Local Networks) .............................................................................. 27
d.
Exclusion E4 (Reactive Power Devices) ................................................................ 29
VI. APPLICATION OF THE DEFINITION OF BULK ELECTRIC SYSTEM ....................... 30
VII. CONCLUSION ..................................................................................................................... 33
i
TABLE OF CONTENTS
Exhibit A
Proposed Definition of “Bulk Electric System”
Exhibit B
Implementation Plan for Proposed Definition of “Bulk Electric System”
Exhibit C
Redlined Comparison of Proposed Definition of “Bulk Electric System”
Exhibit D
White Paper on Bulk Electric System Radial Exclusion (E1) Low Voltage Loop
Threshold – PUBLIC VERSION
Exhibit D
White Paper on Bulk Electric System Radial Exclusion (E1) Low Voltage Loop
Threshold – PRIVILEGED AND CONFIDENTIAL VERSION
Exhibit E
Summary of Development History and Record of Development of Proposed
Definition of “Bulk Electric System”
Exhibit F
Standard Drafting Team Roster for Project 2010-17
ii
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket Nos.
___________
RM12-6-___
RM12-7-___
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF REVISIONS TO THE DEFINITION OF “BULK ELECTRIC
SYSTEM” AND REQUEST FOR EXPEDITED ACTION
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 revisions
completed in Phase 2 of Project 2010-17 to the definition of the term “Bulk Electric System”
(“BES Definition”) in the NERC Glossary of Terms Used in Reliability Standards for
Commission approval. NERC requests that the Commission approve the proposed BES
Definition (Exhibit A) and find that the proposed BES Definition 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), and expedited Commission action to the extent
necessary for the Commission to issue an order on the proposed BES Definition by no later than
March 31, 2014.
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).
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 (“NERC
Glossary”).
2
1
As required by Section 39.5(a)5 of the Commission’s regulations, this petition presents
the technical basis and purpose of the proposed revisions to the BES Definition and a summary
of the development proceedings (Exhibit E). NERC is requesting privileged treatment of
portions of Exhibit D. The proposed BES Definition was approved by the NERC Board of
Trustees on November 21, 2013.
I.
EXECUTIVE SUMMARY
NERC’s proposed BES Definition is an integral part of the NERC Reliability Standards
and is included in the NERC Glossary of Terms Used in Reliability Standards. The development
of the BES Definition occurred in two phases. Phase 1 culminated in the language that is the
subject of Order Nos. 773 and 773-A (“Phase 1 BES Definition”). Phase 2, the subject of this
petition, addresses the Commission’s directives in Order Nos. 773 and 773-A, and responds to
industry concerns raised during development of Phase 1. The proposed revisions to the BES
Definition build upon Phase 1 and include significant improvements to the Inclusions and
Exclusions, without modifying the core definition. In particular, the addition of Note 2 to
Exclusion E1 (Radial Systems), which functionally allows for a configuration with a loop of 50
kV or less to qualify for Exclusion E1, is a well-designed solution that is technically supported
by the analysis provided in Exhibit D and satisfies the Commission’s directives in Order Nos.
773 and 773-A.
The proposed revisions to the BES Definition are expected to result in minimal changes
to the Elements included in the BES, although some changes are expected as Regional Entities
transition to a consistent approach in application of the BES Definition. The proposed revisions
to the BES Definition add clarity and granularity that will allow for greater transparency and
5
18 C.F.R. § 39.5(a) (2013).
2
consistency in the identification of Elements and facilities that make up the Bulk Electric System
(“BES”) and is responsive to the technical and policy concerns discussed in Order Nos. 773 and
773-A. Provided below is a detailed explanation of the elements of the BES Definition and the
proposed Phase 2 revisions.
A.
Overview of the Elements of the BES Definition
The proposed BES Definition consists of a “core” definition and a list of configurations
of facilities that will be included or excluded from the “core” definition, i.e., Inclusions and
Exclusions. The Inclusions address five specific facilities configurations to provide clarity that
the facilities described in these configurations are included in the BES. Similarly, the Exclusions
address four specific facilities configurations that are not included in the BES.
The Inclusions and Exclusions address typical system facilities and configurations such
as generation and radial systems, provide additional granularity that improves consistency, and
provide a practical means to determine the status of common system configurations.
The core definition, with the more granular proposed Inclusions and Exclusions, should
produce consistency in identifying BES Elements across the reliability regions.6 The case-bycase exception process, to add elements to, and remove elements from, the BES adds
transparency and uniformity to the process of determining what constitutes the Bulk Electric
System.7
6
Consistent with Order No. 672, the proposed BES Definition achieves the specific reliability goal of
ensuring that the Definition of BES eliminates regional variations, providing a consistent identification of BES
Facilities across the nation’s reliability regions. 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 321, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶
31,212 (2006). The proposed BES Definition also achieves its reliability goals effectively and efficiently in
accordance with Order No. 672. Id. at P 328.
7
Upon Commission approval of the proposed BES Definition, NERC will file with the Commission
amendments to the NERC Rules of Procedure to include the new BES Definition.
3
B.
Summary of Proposed Revisions to the BES Definition
No changes are proposed to the core BES Definition, Inclusion I3 (Blackstart Resources)
or Exclusion E2 (Behind the Meter Generation). Minor clarifying changes are proposed to:
Inclusion I1 (Transformers);
Inclusion I2 (Generating Resources); and
Inclusion I5 (Static or Dynamic Reactive Power Devices).
Substantive revisions are proposed to Inclusion I4 (Dispersed Power Producing
Resources) and Exclusions E1 (Radial Systems), E3 (Local Networks) and E4 (Reactive Power
Devices), as described below.
Inclusion I4 (Dispersed Power Producing Resources):
o Collector systems, from the point where the generation aggregates to 75
MVA to a common point of connection at a voltage of 100 kV or above,
are proposed to be included in the BES.
Exclusion E1 (Radial Systems):
o A threshold of 50 kV is proposed as the operating voltage below which
loops between radial systems will not preclude the application of
Exclusion E1;8
o In accordance with Order Nos. 773 and 773-A, Exclusion E1 is proposed
to be modified so that it does not apply to tie-lines, i.e., generator
interconnection facilities, for BES generators.
Exclusion E3 (Local Networks):
o In accordance with Order Nos. 773 and 773-A, the 100 kV minimum
operating voltage for Exclusion E3 is proposed for removal;
o In accordance with Order Nos. 773 and 773-A, Exclusion E3 is proposed
to be modified so that it does not apply to tie-lines, i.e., generator
interconnection facilities, for BES generators;
o A revision is proposed to Exclusion E3 to include any part of a permanent
Flowgate.
Exclusion E4 (Reactive Power Devices):
o A revision is proposed to Exclusion E4 to remove ownership implications
consistent with the component-based nature of the BES Definition.
8
This ensures that Elements at or above 100 kV in a looped configuration are not excluded from the BES by
application of Exclusion E1. See Order No. 773-A at P 44.
4
Together, these proposed revisions improve upon the Phase 1 Definition of BES
approved by the Commission in Order Nos. 773 and 773-A and provide a technically grounded
and legally supportable foundation for identifying Elements and facilities that make up the BES.
The proposed BES Definition is designed to ensure that all facilities necessary for operating an
interconnected electric energy transmission network are included in the BES. The proposed BES
Definition is consistent, repeatable, and verifiable and will provide clarity that will assist NERC
and affected entities in implementing Reliability Standards.
C.
Implementation and Request for Expedited Action
The Phase 1 version of the BES Definition approved by the Commission in Order Nos.
773 and 773-A is scheduled to go into effect on July 1, 2014. The implementation plan for the
proposed Phase 2 BES Definition states that the Definition “shall become effective on the first
day of the second calendar quarter after the date that the definition is approved by an applicable
governmental authority…”9 In order to ensure a smooth transition and avoid potential regulatory
uncertainty, NERC requests expedited Commission action to the extent necessary for the
Commission to issue an order on the proposed Phase 2 BES Definition by no later than March
31, 2014.
If approved by the Commission, the proposed Phase 2 BES Definition will supersede, in
its entirety, the Phase 1 version. NERC is requesting expedited Commission action in order to
allow the proposed Phase 2 BES Definition revisions to go into effect on July 1, 2014, the
effective date of the Phase 1 BES Definition. Expedited action is consistent with the
9
See Exhibit B.
5
Commission’s acknowledgement of the need to process revisions to the BES Definition well in
advance of the July 1, 2014 effective date.10
II.
REQUEST FOR PRIVILEGED TREATMENT
Pursuant to 18 C.F.R. § 388.112 (2013), NERC is requesting that portions of Exhibit D,
a white paper on the BES Radial Exclusion (E1) low voltage loop threshold, be treated as
privileged and confidential. Information in Exhibit D includes confidential information as
defined by the Commission’s regulations at 18 C.F.R. Part 388 and orders, as well as NERC
Rules of Procedure. This includes non‐public information related to Registered Entity sensitive
business information and confidential information regarding critical energy infrastructure. In
accordance with the Commission’s Rules of Practice and Procedure, 18 C.F.R. § 388.112, a nonpublic version of the information redacted from the public filing is being provided under separate
cover. Because information in Exhibit D is deemed confidential by NERC, Regional Entities
and Registered Entities, NERC requests that the confidential, non‐public information be
provided special treatment in accordance with the above regulation.
III.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:11
10
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,
Order Granting Extension of Time, 143 FERC ¶ 61,231 at P 16 (2013)(“the Commission expects NERC to file the
changes to comply with the Order Nos. 773 and 773-A directives in sufficient time to allow the Commission to
process NERC’s proposal in response to the directives well in advance of the July 1, 2014 effective date.”).
11
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.
6
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]
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]
IV.
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005,12 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
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1)13
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)14 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a)15 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.
12
13
14
15
16 U.S.C. § 824o (2006).
Id. § 824(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a) (2012).
7
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 FPA16 and Section 39.5(c)17 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 BES Definition was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.18 NERC
develops Definitions in accordance with Section 300 (Reliability Standards Development) of its
Rules of Procedure and the NERC Standard Processes Manual.19 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 the criteria for approving Reliability Standards.20 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 Definition before the
16
16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).
18
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
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.”).
19
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.
20
116 FERC ¶ 61,062 at P 250 (2006).
17
8
Definition is submitted to the Commission for approval. The proposed BES Definition was
developed in accordance with NERC’s Commission-approved, ANSI-accredited processes for
developing and approving Definitions. Exhibit E includes a summary of the development
history and record of development of the Definition, and details the processes followed to
develop the Definition.
C.
Procedural Background
1.
Order No. 693
On March 16, 2007, in Order No. 693, pursuant to section 215(d) of the FPA, the
Commission approved 83 of 107 proposed Reliability Standards, six of eight proposed regional
differences, and the NERC Glossary, which includes NERC’s BES Definition.21
2.
Order Nos. 743 and 743-A
On November 18, 2010, the Commission revisited the BES Definition in Order No. 743,
which directed NERC, through NERC’s Reliability Standards Development Process, to revise its
BES Definition to ensure that it encompasses all facilities necessary for operating an
interconnected transmission network.22 The Commission also directed NERC to address the
Commission’s technical and policy concerns. Among the Commission’s concerns were: (i)
inconsistencies in the application of the definition; (ii) a lack of oversight, and (iii) exclusion of
facilities from the BES required for the operation of the interconnected transmission network. In
Order No. 743, the Commission concluded that the best way to address these concerns was to
eliminate the Regional Entity discretion to define the BES without NERC or Commission
review, maintain a bright-line threshold that includes all facilities operated at or above 100 kV
21
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶
31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
22
Order No. 743, 133 FERC ¶ 61,150 at P 16.
9
except defined radial facilities, and adopt an exemption process and criteria for removing from
the BES those facilities that are not necessary for operating the interconnected transmission
network. In Order No. 743, the Commission allowed NERC to “propose a different solution that
is as effective as, or superior to, the Commission’s proposed approach in addressing the
Commission’s technical and other concerns so as to ensure that all necessary facilities are
included within the scope of the definition.”23 The Commission directed NERC to file the
revised BES Definition and its process to exempt facilities from inclusion in the BES within one
year of the effective date of the final rule.24 In Order No. 743-A, the Commission reaffirmed its
determinations in Order No. 743.
On January 25, 2012, NERC submitted two petitions pursuant to the directives in Order
No. 743: (1) NERC’s proposed revision to the BES Definition which includes provisions to
include and exclude facilities from the “core” definition; and (2) revisions to NERC’s Rules of
Procedure to add a procedure creating an exception process to classify or de-classify an element
as part of the BES. In Docket No. RM12-6-000, NERC filed a petition requesting Commission
approval of a revised BES Definition in the NERC Glossary. The definition consists of a “core”
definition and a list of facilities and configurations that will be included in, or excluded from, the
“core” definition. NERC proposed the following “core” BES Definition:
Unless modified by the [inclusion and exclusion] lists shown
below, all Transmission Elements operated at 100 kV or higher
and Real Power and Reactive Power resources connected at 100
kV or higher. This does not include facilities used in the local
distribution of electric energy.
The Commission issued the BES Notice of Proposed Rulemaking (“NOPR”) on June 22, 2012,
and required that comments be filed within 60 days after publication in the Federal Register, or
23
24
Id.
Id. at P 113.
10
September 4, 2012.25 While seeking comment on various provisions of NERC’s petitions, the
NOPR proposed to approve NERC’s modification to the currently-effective BES Definition and
changes to the Rules of Procedure to add the exception process. The NOPR also requested
comment on the appropriate role for NERC and the Commission in the identification of BES
facilities and elements. NERC submitted comments on September 4, 2012, and reply comments
on September 19, 2012.26
3.
Order Nos. 773 and 773-A
On December 20, 2012, in Order No. 773, the Commission issued a Final Rule approving
modifications to the currently-effective definition of BES developed by NERC. In Order No.
773-A, the Commission issued an order on rehearing and clarification. In the Orders, the
Commission has directed NERC to: (1) modify the exclusions for radial systems (Exclusion E1)
and local networks (Exclusion E3) so that they do not apply to tie-lines, i.e. generator
interconnection facilities, for BES generators; and (2) modify the local network exclusion to
remove the 100 kV minimum operating voltage to allow systems that include one or more looped
configurations connected below 100 kV to be eligible for the local network exclusion.27 The
proposed revisions to the BES Definition address the Commission’s concerns, as explained
below.
On May 23, 2013, NERC filed a Motion for an Extension of Time, from July 1, 2013 to
July 1, 2014, of the effective date of the BES Definition. NERC explained that, without an
extension of time, there would be a period of time during which the existing BES Definition
25
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,
139 FERC ¶ 61,247 (June 22, 2012) (“NOPR”).
26
NERC’s initial comments are available here:
http://www.nerc.com/files/FINAL_Comments_BES_NOPR_complete.pdf and NERC’s reply comments are
available here: http://www.nerc.com/files/FINAL_BES_NOPR_Reply%20comments_clean.pdf.
27
Order No. 773 at PP 155, 164.
11
without the Commission-directed modifications would be in effect. On June 13, 2013, the
Commission granted NERC’s request for an extension of time.28
V.
JUSTIFICATION FOR APPROVAL
As discussed herein, the proposed BES Definition is just, reasonable, not unduly
discriminatory or preferential, and is in the public interest. Provided below is an explanation of
the components of the BES Definition and the proposed revisions.
A.
Discussion of Proposed Revisions to the Definition of “Bulk Electric System”
No changes are proposed to the core BES Definition, Inclusion I3 (Blackstart Resources)
or Exclusion E2 (Behind the Meter Generation). Minor clarifying changes are proposed to
Inclusions I1 (Transformers), I2 (Generating Resources), and I5 (Static or Dynamic Reactive
Power Devices). Substantive revisions are proposed to Inclusion I4 (Dispersed Power Producing
Resources) and Exclusions E1 (Radial Systems), E3 (Local Networks), and E4 (Reactive Power
Devices).
1.
“Core” Definition
Bulk Electric System (BES): Unless modified by the lists shown below, all
Transmission Elements operated at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher. This does not include facilities used in the local
distribution of electric energy.
No revisions are proposed to the core Definition or the accompanying “note”29 which
applies to the entire Definition and recognizes that Elements may be included or excluded on a
case-by-case basis through the Rules of Procedure exception process. The core Definition is
used to establish the bright-line of 100 kV, the overall demarcation point between Bulk Electric
System and Non-Bulk Electric System Elements.
28
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,
Order Granting Extension of Time, 143 FERC ¶ 61,231 (2013).
29
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
12
2.
Inclusions
Inclusions identify specific facility configurations to provide clarity that the facilities
described are included in the Bulk Electric System (unless the facilities are excluded based on
one of the specific Exclusions in the BES Definition) and reduce the potential for the exercise of
discretion and subjectivity.
a. Inclusion I1 (Transformers)
Inclusion I1 (Transformers): Transformers with the primary terminal and at least one
secondary terminal operated at 100 kV or higher unless excluded by application of
Exclusion E1 or E3.
A minor clarifying change is proposed to Inclusion I1—the phrase “under Exclusion E1
or E3” is proposed to be changed to “by application of Exclusion E1 or E3.” Inclusion I1
provides clarification regarding exactly which transformers are part of the Bulk Electric System.
This clarification is necessary because transformers have windings operating at different voltages
and multiple windings in some circumstances. Inclusion I1 includes in the Bulk Electric System
those transformers operating at 100 kV or higher on the primary winding and at least one
secondary winding, so as to be in concert with the core definition. The 100 kV threshold for
secondary windings provides a clear demarcation between facilities used to transfer power as
opposed to those that serve Load because transformers with two terminals >100 kV transfer
power between portions of the BES. In Order No. 773, the Commission stated that Inclusion I1
is “a reasonable approach to identifying transformers that are appropriately included as part of
the bulk electric system.”30
30
Order No. 773 at P 80.
13
b. Inclusion I2 (Generating Resources)
Inclusion I2 (Generating Resources): Generating resource(s) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of
100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
Inclusion I2 has been revised for clarity but is substantively unchanged. The language of
Inclusion I2 has been separated into sub-parts (a) and (b) in order to clarify the relationship
between these sub-parts—this is an “or” statement. Inclusion I2 mirrors the text of the NERC
Statement of Compliance Registry Criteria (Appendix 5B of the NERC Rules of Procedure) for
generating units, and Inclusion I2 was approved by the Commission in Order No. 773.31 The
Commission “agree[d] with NERC and other commenters that multiple step-up transformers that
are solely used to deliver the generation to the bulk electric system at 100 kV or above qualify
the generator and the step-up transformers pursuant to inclusion I2.”32
c. Inclusion I3 (Blackstart Resources)
Inclusion I3 (Blackstart Resources): Blackstart Resources identified in the
Transmission Operator’s restoration plan.
No revisions are proposed to Inclusion I3. Blackstart Resources are vital to the reliable
operation of the Bulk Electric System.33 Consequently, Blackstart Resources are included in the
BES regardless of their size (MVA) or the voltage at which they are connected. The term
“restoration plan” in inclusion I3 refers to the restoration plans in the EOP Reliability
31
Order No. 773 at P 91.
Id.
33
The term “Blackstart Resource” is defined in the NERC Glossary as “A generating unit(s) and its
associated set of equipment which has the ability to be started without support from the System or is designed to
remain energized without connection to the remainder of the System, with the ability to energize a bus, meeting the
Transmission Operator’s restoration plan needs for real and reactive power capability, frequency and voltage
control, and that has been included in the Transmission Operator’s restoration plan.”
32
14
Standards.34 In Order No. 773, the Commission noted that “NERC’s inclusion of blackstart
resources in the definition is an improvement to the definition.”35
d. Inclusion I4 (Dispersed Power Producing Resources)
Dispersed power producing resources are small-scale generation technologies using a
system designed primarily for aggregating capacity providing an alternative to, or an
enhancement of, the traditional electric power system. Examples could include, but are not
limited to, solar, geothermal, energy storage, flywheels, wind, micro-turbines, and fuel cells.
Inclusion I4 (Dispersed Power Producing Resources): Dispersed power producing
resources that aggregate to a total capacity greater than 75 MVA (gross nameplate
rating), and that are connected through a system designed primarily for delivering such
capacity to a common point of connection at a voltage of 100 kV or above. Thus, the
facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Inclusion I4 has been revised to clarify the facilities designated as BES by application of
this Inclusion and to include the collector system at the point of aggregation, i.e., “[t]he system
designed primarily for delivering capacity from the point where those resources aggregate to
greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.”
i. Inclusion of Collector Systems in the BES
In the BES NOPR, the Commission requested comments on this issue—whether
Inclusion I4 “includes as part of the bulk electric system the individual elements (from each
energy-producing resource at the site through the collector system to the common point at a
voltage of 100 kV or above) used to aggregate the capacity and any step-up transformers used to
34
See Order No. 773 at P 102 (“We also agree with NERC’s statement that the ‘restoration plan’ in inclusion
I3 refers to the restoration plans in the EOP Reliability Standards.”).
35
Order No. 773 at P 102.
15
connect the system to a common point at a voltage of 100 kV or above.” NERC, in its comments
on the BES NOPR, stated that “[e]nergy delivery elements in collector systems and
interconnection facilities were specifically not included in Inclusion I4, which deals exclusively
with generation resources. This was intended to avoid categorically including as part of the BES
assets that may include local distribution facilities.”
While the Commission did not direct NERC to categorically include collector systems
pursuant to Inclusion I4, the Commission stated that it “disagrees that collector systems
described in inclusion I4 that solely deliver aggregated generation to the bulk electric system
contain local distribution facilities because power is delivered from the collector system to the
bulk electric system.”36 Upon reflection of the Commission’s statement in Order No. 773 and
input from Commission technical staff during standard development, the drafting team
reconsidered its earlier position and revised Inclusion I4 to include collector systems from the
point where the generation aggregates to 75 MVA to a common point of connection at a voltage
of 100 kV or above.
There are significant differences in collector system configurations; therefore, the
standard drafting team did not establish a continent-wide bright-line determination for such
Elements in their entirety. Rather, the standard drafting team identified the portions of the
collector system which consistently provide a reliability benefit to the interconnected
transmission network and are easily identified within collector systems. The result identifies the
point of aggregation of 75 MVA and above and the interconnecting facilities to the
interconnected transmission network. The aggregation threshold is consistent with the
aggregation of capacity in Inclusion I2 and recognizes that the loss of those facilities would
36
Order No. 773 at P 114.
16
represent a loss of 75 MVA capacity to the Bulk Electric System and thus a potential reliability
impact on the operation of the BES.
As the Commission has noted, a bright-line threshold eliminates ambiguity.37 While the
Commission has stated that “[i]n general…it is appropriate to have the bulk electric system
contiguous, without facilities or elements ‘stranded’ or ‘cut-off’ from the remainder of the bulk
electric system…”,38 the standard drafting team determined that the inclusion of the collector
system in Inclusion I4 is appropriate and consistent with the overall tenet of the BES Definition,
which is to identify Elements that provide a reliability benefit to the interconnected transmission
network. On a “bright-line” basis, the standard drafting team only included those portions of the
collector system that are strictly utilized for delivering the aggregated capacity of the dispersed
power resources to the interconnected transmission system. The intervening equipment is being
treated in a similar fashion to Cranking Paths. Furthermore, where collector systems support the
reliable operation of the surrounding interconnected transmission system and do not have a
distribution function, those excluded facilities may be candidates for inclusion through the BES
Exception Process.
ii. Inclusion of Variable Generation Resources
Consistent with the Commission’s recognition that the purpose of Inclusion I4 is to
include variable generation,39 all forms of generation resources, including variable generation
37
Order No. 743 at P 141.
Order No. 773 at P 165.
39
Order No. 773 at P 115 (“We disagree . . . that inclusion I4 should be interpreted to not include the
dispersed power producing resources within a wind plant in the [BES]. We agree with NERC’s statement that the
purpose of this inclusion is to include such variable generation (e.g., wind and solar resources). NERC noted that,
while such generation could be considered subsumed in inclusion I2 (because the gross aggregate nameplate rating
of the power producing resources must be greater than 75 MVA), NERC considered it appropriate for clarity to add
this separately-stated inclusion to expressly cover dispersed power producing resources using a system designed
primarily for aggregating capacity. In addition, although dispersed power producing resources (wind, solar, etc.) are
typically variable suppliers of electrical generation to the interconnected transmission network, there are
geographical areas that depend on these types of generation resources for the reliable operation of the interconnected
38
17
resources, continue to be included in the proposed revisions to the BES Definition. This is not a
proposed change. Owners and operators of variable generation resources meeting the Registry
Criteria have always been subject to registration and compliance with Reliability Standards. As
the Commission noted in Order No. 773, “owners and operators of these resources that meet the
75 MVA gross aggregate nameplate rating threshold are, in some cases, already registered and
have compliance responsibilities as generator owners and generator operators.”40
Given the increasing penetration of wind, solar, and other non-traditional forms of
generation, the standard drafting team believes that continuing the inclusion of individual
variable generation units within the scope of a bright-line BES Definition is appropriate to ensure
that, where necessary to support reliability, these units may be subject to Reliability Standards.
e. Inclusion I5 (Static or Dynamic Reactive Power Devices)
Inclusion I5 (Static or Dynamic Reactive Power Devices): Static or dynamic devices
(excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1
unless excluded by application of Exclusion E4.
Inclusion I5 has been revised to clarify that Exclusion E4 (Reactive Power Devices)
would exclude Elements identified for inclusion in Inclusion I5. As the Commission noted in
Order No. 773, Exclusions E1 and E3 would not override Inclusion I5 because Exclusions E1
and E3 exclude transmission elements only and not resources.41 Exclusion E4, which is specific
to resources (i.e., Reactive Power devices), would override Inclusion I5. This clarification is an
improvement to the BES Definition as it makes the relationship between specific and related
transmission network. The Commission believes that owners and operators of these resources that meet the 75
MVA gross aggregate nameplate rating threshold are, in some cases, already registered and have compliance
responsibilities as generator owners and generator operators.”).
40
Id.
41
Order No. 773 at P 123 (“The Commission does not agree with G&T Cooperatives that Exclusions E1 and
E3 override inclusion I5 and exclude the reactive power devices. Exclusions E1 and E3 exclude transmission
elements only and not resources.”).
18
Inclusions and Exclusions transparent, which will facilitate consistent application of the BES
Definition by industry.
The Commission approved Inclusion I5 in Order No. 773 and stated that “the inclusion
adds clarity to the application of the bulk electric system definition by providing specific criteria
for reactive power devices.”42 Similarly, the proposed revision to Inclusion I5 provides
additional clarity.
3.
Exclusions
Exclusions identify facility configurations that should not be included in the Bulk Electric
System. The four Exclusions are for: (1) radial systems; (2) behind-the-meter generating units;
(3) local networks; and (4) retail customer Reactive Power devices. As explained in Section VI
below, Exclusions do not automatically supersede Inclusions. For example, if an Element
qualifies under Inclusion I3 (Blackstart Resources), the Element would not be eligible for
exclusion by application of any potential Exclusion (in this case, likely Exclusion E1 or
Exclusion E3) because Blackstart Resources are included in the BES regardless of configuration
or location.
a. Exclusion E1 (Radial Systems)
Exclusion E1 (Radial Systems): A group of contiguous transmission Elements that
emanates from a single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified
in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail generation less than
or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on prints
or one-line diagrams for example, does not affect this exclusion.
42
Order No. 773 at P 123.
19
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or less,
between configurations being considered as radial systems, does not affect this exclusion.
There are two substantive proposed revisions to Exclusion E1: (1) the addition of Note 2;
and (2) the addition of Inclusions I2 and I4 in parts (b) and (c). As explained below, these
proposed revisions satisfy the Commission’s directives in Order Nos. 773 and 773-A. The
technical analysis provided in Exhibit D supports the proposed addition of Note 2 and will allow
the Commission to make an informed decision.
Exclusion E1 (Radial Systems) provides for the exclusion of radial systems that meet the
specific criteria identified in the exclusion language. By definition, radial systems only consist
of “transmission Elements.” Therefore, Exclusion E1 does not allow for the exclusion of Real
Power and Reactive Power resources captured by Inclusions I2 through I5, nor generator step-up
transformers or portions of collector systems captured by Inclusions I2 and I4.
i.
Networked Configuration with a sub-100 kV Loop
In Order No. 773, the Commission held that radial systems with elements operating at
100 kV or higher in a configuration that emanate from two or more points of connection cannot
be deemed “radial” if the configuration remains contiguous through elements that are operated
below 100 kV.43 The Commission held that such a configuration is a networked configuration
and does not qualify for Exclusion E1. The Commission included a depiction of this
configuration, reproduced below, in Order No. 773 as Figure 3.
43
Order No. 773 at P 155.
20
FERC Order No. 773 Figure 3
Networked Configuration w/69 kV Loop
The Commission disagreed with commenters that this decision is contrary to the language
of Exclusion E1 and directed NERC to ensure that Elements at or above 100 kV in a looped
configuration are not excluded from the BES under Exclusion E1.44 Similarly, the Commission
directed NERC to remove the 100 kV floor in Exclusion E3 (Local Networks).45 Removing the
100 kV minimum operating voltage in Exclusion E3 allows networked configurations below 100
kV, that may not otherwise be eligible for Exclusion E1, to be eligible for Exclusion E3.
In consideration of the Commission’s directives, Exclusion E1 has been revised to
include Note 2. Note 2 to Exclusion E1 states that the “presence of a contiguous loop, operated
at a voltage level of 50 kV or less, between configurations being considered as radial systems,
does not affect this exclusion.” Under the Phase 1 BES Definition, the presence of a loop meant
that a configuration would be ineligible for consideration under Exclusion E1 and instead would
44
45
Order No. 773-A at P 36.
Order No. 773-A at P 125.
21
have to be considered under Exclusion E3. Note 2 functionally allows for a configuration with a
loop of 50 kV or less to qualify for Exclusion E1– this is illustrated below in Figure A.
NERC Figure A Networked Configuration w/ a 50 kV (or less) Loop
This improvement to the BES Definition is responsive to the Commission’s concerns in
Order Nos. 773 and 773-A. The Commission stated in Order No. 773-A that “[i]t strikes us as
unreasonable to characterize lines as radial by ignoring connecting facilities below 100 kV.”46
Instead, Note 2 recognizes the physical realities of the interconnected transmission system. For
example, it would be an illogical result for two otherwise radial systems connected by a 2 kV
loop to be deemed a local network simply by virtue of the presence of this 2 kV loop. With this
understanding, the standard drafting team set out to determine at which voltage level the
presence of a loop could create an impact on the BES. The standard drafting team conducted
technical analysis including modeling the physics of loop flows through sub-100 kV systems, in
order to determine an appropriate threshold.
46
Id.
22
In Order Nos. 773 and 773-A, the Commission indicated that additional factors beyond
impedance must be considered to demonstrate that looped or networked connections operating
below 100 kV need not be considered in the application of Exclusion E1.47 The standard
drafting team conducted a two-step process to establish a technical justification for the
establishment of a voltage threshold below which sub-100 kV loops do not preclude the
application of Exclusion E1.
Step 1: A review was performed to determine the minimum voltage levels that
are monitored by Balancing Authorities, Reliability Coordinators, and
Transmission Operators for Interfaces, Paths, and Monitored Elements. This
minimum voltage level reflects a value that industry experts consider necessary to
monitor and facilitate the operation of the Bulk Electric System. This step
provided a technically sound approach to screen for a minimum voltage limit that
served as a starting point for the technical analysis performed in Step 2 of this
study.
Step 2: Technical studies modeling the physics of loop flows through sub-100
kV systems were performed to establish which voltage level, while less than 100
kV, should be considered in the evaluation of Exclusion E1.
Under Step 1, each Region was requested to provide the key groupings of elements they
monitor to ensure reliable operation of the interconnected transmission system. This list,
contained in Exhibit D Appendix 1, was reviewed to identify the lowest voltage element in the
major element groupings monitored by operating entities in the eight Regions. Identification of
this lowest voltage level served as a starting point to begin a closer examination into the voltage
level where the presence of a contiguous loop should not preclude the evaluation of radial
systems when applying Exclusion E1 of the BES definition.
The threshold of 30 kV was established in Step 1 as a reasonable starting point to initiate
the technical sensitivity analysis performed in Step 2 of this study. The purpose of this step was
47
Order No. 773 at P 155, n.139 (“the Commission believes that excluding these configurations solely on the
level of impedance does not consider other factors, including voltage, the system configuration, type of conductors,
length of conductors, and proximity of the networked system in the interconnected transmission network.”).
23
to determine if there is a technical justification to support a voltage threshold for the purpose of
determining whether facilities greater than 100 kV can be considered to be radial when applying
the BES Definition Exclusion E1. If the resulting voltage threshold was deemed appropriate
through technical study efforts, then contiguous loop connections operated at voltages below this
value would not preclude the application of Exclusion E1. Conversely, contiguous loops
connecting radial lines at voltages above this kV value would negate the ability for an entity to
use Exclusion E1 for the subject facilities.
This study focused on two typical configurations: a distribution loop and a
sub‐transmission loop. Examples of these configurations are depicted below in Figures B and C.
NERC FIGURE B: Example of a Radial
System with Low Voltage Distribution Loop
NERC FIGURE C: Example of a Radial
System with Sub-Transmission Loop
The study evaluated a range of voltages for the loop and the parallel transmission system
with the goal of determining the voltage level below which single Contingencies on the
transmission system would not result in power flow from a low voltage distribution or sub24
transmission loop to the BES. The study included sensitivity analysis varying the loads and
impedances. Variations in loop and transmission system impedances account for a range of
physical parameters such as conductor length, conductor type, system configuration, and
proximity of the loop to the transmission system. This study provided the low voltage floor that
can be used as a consideration for BES Exclusion E1.
The proposed revisions are an equally effective and efficient solution to addressing the
Commission’s concerns in Order Nos. 773 and 773-A. The analysis described herein establishes
that a 50 kV threshold for sub-100 kV loops, such as those depicted above in Figures B and C,
does not preclude the application of Exclusion E1. This approach should ease the administrative
burden on entities in order to prove that they qualify for an Exclusion and is an improvement to
the BES Definition.
ii.
Generator Interconnection Facilities
The proposed addition of Inclusions I2 (Generating Resources) and I4 (Dispersed Power
Producing Resources) in parts (b) and (c) of Exclusion E1 satisfy the Commission’s directive to
modify Exclusions E1 and E3 to ensure that generator interconnection facilities at or above 100
kV connected to BES generators identified in Inclusion I2 are not excluded from the BES.48
In Order No. 773, the Commission stated that, if the generator is necessary for the
operation of the interconnected transmission network, it is appropriate to have the generator
interconnection facility operating at or above 100 kV that delivers the generation to the BES
included as well.49 Consistent with this directive and with this logic, parts (b) and (c) of
Exclusion E1 have been modified to incorporate references to Inclusions I2 and I4. This
48
Order No. 773-A at P 50 (“We grant rehearing to the extent that, rather than direct NERC to implement
exclusions E1 and E3 as described above, we direct NERC to modify the exclusions pursuant to FPA section
215(d)(5) to ensure that generator interconnection facilities at or above 100 kV connected to bulk electric system
generators identified in inclusion I2 are not excluded from the bulk electric system.”).
49
Order No. 773 at PP 164-65.
25
proposed revision ensures that generator interconnection facilities at or above 100 kV connected
to BES generators identified in Inclusions I2 and I4 are not excluded from the BES.
b. Exclusion E2 (Behind the Meter Generation)
Exclusion E2 (Behind the Meter Generation): A generating unit or multiple generating
units on the customer’s side of the retail meter that serve all or part of the retail Load with
electric energy if: (i) the net capacity provided to the BES does not exceed 75 MVA, and
(ii) standby, back-up, and maintenance power services are provided to the generating unit
or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Generator Owner or Generator Operator, or under
terms approved by the applicable regulatory authority.
No revisions are proposed to Exclusion E2. Exclusion E2 excludes from the BES a
generating unit or units on the customer’s side of the retail meter that serves all or part of the
retail Load, so long as the following two conditions are met: (i) the net capacity provided by the
generating unit(s) to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit(s) or the retail Load by a
Balancing Authority, or pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority. Under these
circumstances, the generating unit(s) are not necessary for the reliable operation of the
interconnected transmission system, and therefore do not need to be included in the BES,
because they serve a single retail Load, provide a limited amount of capacity to the BES, and are
fully backed up by other resources. The Commission approved Exclusion E2 in Order No. 773
and noted that it “provides additional clarity to the definition of bulk electric system.”50
50
Order No. 773 at P 183.
26
c. Exclusion E3 (Local Networks)
Exclusion E3 (Local Networks): Local networks (LN): A group of contiguous
transmission Elements operated at less than 300 kV that distribute power to Load rather
than transfer bulk power across the interconnected system. LN’s emanate from multiple
points of connection at 100 kV or higher to improve the level of service to retail
customers and not to accommodate bulk power transfer across the interconnected system.
The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not include
generation resources identified in Inclusions I2, I3, or I4 and do not have an aggregate
capacity of non-retail generation greater than 75 MVA (gross nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy originating
outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
Exclusion E3 has been substantively revised in accordance with the Commission’s
directives in Order Nos. 773 and 773-A; the 100 kV minimum operating voltage for Exclusion
E3 has been removed. In addition, several clarifying changes are proposed for approval.
Exclusion E3 (Local Networks) provides for the exclusion of local networks that meet the
specific criteria identified in the exclusion language. By definition, local networks only consist
of “transmission Elements.” Therefore, Exclusion E3 does not allow for the exclusion of Real
Power and Reactive Power resources captured by Inclusions I2 through I5, nor generator step-up
transformers or portions of collector systems captured by Inclusions I2 and I4.
i.
Removal of the 100 kV Floor
In Order Nos. 773 and 773-A, the Commission directed NERC to modify Exclusion E3 to
remove the 100 kV minimum operating voltage in the local network definition.51 In Order No.
773-A, the Commission agreed that “removing the phrase ‘or above 100 kV but’ from the
definition of local networks in the first sentence of exclusion E3 is an appropriate way to meet
51
Order No. 773 at P 199 (“we direct NERC to modify exclusion E3 to remove the 100 kV minimum
operating voltage in the local network definition.”); Order No. 773-A at P 34.
27
the Commission’s directive to remove the 100 kV minimum operating voltage in the local
network definition.”52 Consistent with the Commission’s direction, the phrase “or above 100 kV
but” has been removed from Exclusion E3 in the proposed BES Definition.
i.
Generator Interconnection Facilities
The proposed addition of Inclusions I2 (Generating Resources) and I4 (Dispersed Power
Producing Resources) in part (a) of Exclusion E3 satisfy the Commission’s directive to modify
Exclusions E1 and E3 to ensure that generator interconnection facilities at or above 100 kV
connected to BES generators identified in Inclusion I2 are not excluded from the BES.53
In Order No. 773, the Commission stated that, if the generator is necessary for the
operation of the interconnected transmission network, it is appropriate to have the generator
interconnection facility operating at or above 100 kV that delivers the generation to the BES
included as well.54 Consistent with this directive and with this logic, part (a) of Exclusion E3
have been modified to incorporate references to Inclusions I2 and I4. This proposed revision
ensures that generator interconnection facilities at or above 100 kV connected to BES generators
identified in Inclusions I2 and I4 are not excluded from the BES.
ii.
Flowgate
A change is proposed to part (c) of Exclusion E3 to include any part of a permanent
Flowgate. The standard drafting team believes that the reliable operation of the interconnected
transmission system requires operator situational awareness of any and all parts of permanent
Flowgates in order to adequately provide for reliable operation.55 Hence, the presence of any
52
53
54
55
Order No. 773-A at P 40.
Order No. 773-A at P 50.
Order No. 773 at PP 164-65.
See Consideration of Comments: Project 2017-17: August 2, 2013 at p. 17.
28
part of a Flowgate should preclude the application of Exclusion E3 and is an improvement to the
BES Definition.
iii.
Clarifying Changes
In the revised BES Definition, the term “retail customer Load” has been simplified to
“retail customers” in order to provide clarity. A clarifying change is also proposed to part (b) to
make clear that the term “Power” refers to “Real Power,” rather than Reactive Power.56 “Real
Power” is defined in the NERC Glossary as “[t]he portion of electricity that supplies energy to
the load.” These revisions clarify the plain words of the proposed BES Definition.
d. Exclusion E4 (Reactive Power Devices)
Exclusion E4 (Reactive Power Devices): Reactive Power devices installed for the sole
benefit of a retail customer(s).
Exclusion E4 has been revised to remove ownership implications as the BES Definition
is a component-based definition and does not take into account the ownership of the actual
equipment. Exclusion E4 is the technical equivalent of Exclusion E2 for reactive power devices.
The Commission accepted Exclusion E4 in Order No. 773.57
The proposed revision to Exclusion E4 is responsive to concerns raised by industry
representatives, which have noted that Exclusion E4 should not be confined to such devices that
are owned and operated by a retail customer solely for its own use because there are instances in
which capacitor banks have been installed for the benefit of a steel-making facility but, for
various reasons, that equipment is owned, operated and maintained by its local utility. In Order
56
The term “Reactive Power” is defined in the NERC Glossary as “The portion of electricity that establishes
and sustains the electric and magnetic fields of alternating-current equipment. Reactive power must be supplied to
most types of magnetic equipment, such as motors and transformers. It also must supply the reactive losses on
transmission facilities. Reactive power is provided by generators, synchronous condensers, or electrostatic
equipment such as capacitors and directly influences electric system voltage. It is usually expressed in kilovars
(kvar) or megavars (Mvar).”
57
Order No. 773 at P 237.
29
No. 773, rather than directing such a change, the Commission noted that this issue could be
explored by NERC in the development of Phase 2 of the BES Definition.58 The proposed
revision to Exclusion E4 improves the clarity of this Exclusion and is consistent with the purpose
of the BES Definition.
VI.
APPLICATION OF THE DEFINITION OF BULK ELECTRIC SYSTEM
The proposed BES Definition is generally applied in three steps, as discussed below.
Going forward, NERC will work with industry regarding the application of the BES Definition
to the configuration of Elements.
STEP 1: CORE DEFINITION: The core definition is used to establish the bright-line of
100 kV, the overall demarcation point between BES and Non-BES Elements. The core BES
Definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher, as included in the BES. To fully appreciate the scope of the core definition, an
understanding of the term “Element” is needed. “Element” is defined in the NERC Glossary as:
“Any electrical device with terminals that may be connected to other electrical devices such as a
generator, transformer, circuit breaker, bus section, or transmission line. An element may be
comprised of one or more components.”
STEP 2: INCLUSIONS: This step involves applying the specific Inclusions, provides
additional clarification for the purposes of identifying specific Elements that are included in the
BES. The Inclusions address Transmission Elements and Real Power and Reactive Power
resources with specific criteria to provide for a consistent determination of whether an Element is
classified as BES or non-BES. There are five Inclusions in the Definition. The facilities
described in Inclusions I1, I2, I4 and I5 are each operated (if transformers – Inclusion I1) or
58
Order No. 773 at P 237.
30
connected (if generating resources, dispersed power producing resources or Reactive Power
resources – Inclusions I2, I4 and I5) at or above the 100 kV threshold. Inclusion I3 encompasses
Blackstart Resources identified in a Transmission Operator’s restoration plan, which are
necessary for the reliable operation of the interconnection transmission system and should be
included in the BES regardless of their size (MVA) or the voltage at which they are connected.
STEP 3: EXCLUSIONS: This step evaluates specific situations for potential exclusion
from the BES. The exclusion language is written to specifically identify Elements or groups of
Elements for exclusion from the BES. Step three (3) should be applied in the following
sequence:
Exclusion E2 (Behind the Meter Generation) provides for the specific exclusion
of certain Real Power resources that reside behind-the-retail meter (on the
customer’s side) and supersedes the more general Inclusion I2 (Generating
Resources). Behind-the-meter generation that meets these specific criteria do not
affect reliability of the BES because the net capacity supplied to the BES is less
than 75 MVA and the specific criteria impose obligations to support reliability
when the resources are unavailable.
Exclusion E4 (Reactive Power Devices) provides for the specific exclusion of
Reactive Power devices installed for the sole benefit of a retail customer(s) and
supersedes the more general Inclusion I5 (Static or Dynamic Reactive Power
Devices). Reactive Power devices installed for the sole benefit of a retail
customer are, by definition, not required for operation of the interconnected
transmission system.
Exclusion E3 (Local Networks) provides for the exclusion of local networks that
meet the specific criteria identified in the exclusion language. Exclusion E3 does
not allow for the exclusion of Real Power and Reactive Power resources captured
by Inclusions I2 through I5. In instances where a transformer (under Inclusion I1)
is an Element of a local network (under Exclusion E3), the transformer would be
excluded pursuant to Exclusion E3. Exclusion E3 may not be used to exclude
transmission Elements (captured by the core definition and Inclusion I1) when
Real Power resources are present that are captured by Inclusion I2, I3, or I4. This
assures that interconnection facilities for BES generators are not excluded.
Exclusion E1 (Radial Systems) provides for the exclusion of ‘transmission
Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. Exclusion E1 does not allow for the exclusion of Real Power
31
and Reactive Power resources captured by Inclusions I2 through I5. In instances
where a transformer (under Inclusion I1) is an Element of a radial system (under
Exclusion E1), the transformer would be excluded pursuant to Exclusion E1.
Exclusion E1 may not be used to exclude transmission Elements (captured by the
core definition and Inclusion I1) when Real Power resources are present that are
captured by Inclusion I2, I3, or I4. This assures that interconnection facilities for
BES generators are not excluded.
Merely applying the core Definition, and the Inclusions or Exclusions is not necessarily
the end of the inquiry regarding whether an Element is part of the BES as entities may seek a
case-specific exception.
NERC will continue to work with industry regarding the application of the BES
Definition. As explained herein, the proposed BES Definition is a significant improvement that
is technically supported and satisfies the Commission’s directives in Order Nos. 773 and 773-A.
The proposed BES Definition is consistent, repeatable, and verifiable and will provide clarity
that will assist NERC and affected entities in implementing Reliability Standards.
32
VII.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:
•
approve the proposed BES Definition and associated elements included in Exhibit A,
effective as proposed herein;
•
approve the implementation plan included in Exhibit B; and
•
issue an order on the proposed BES Definition by no later than March 31, 2014.
Respectfully submitted,
/s/ Stacey Tyrewala
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]
Counsel for the North American Electric
Reliability Corporation
Date: December 13, 2013
33
Exhibit A
Proposed Definition
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Page 1 of 3
Project 2010-17 Definition of Bulk Electric System (Phase 2)
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Page 2 of 3
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Version History
Phase
Date
Action
Change
Tracking
1
1/25/12
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
2
11/21/13
Adopted by NERC Board of Trustees
Phase 2
clarifications to
the original
revisions.
Respond to
directives in
FERC Orders 773
and 773-A.
Page 3 of 3
Exhibit B
Implementation Plan
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
None.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after the date that
the definition 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 definition
shall become effective on the first day of the first calendar quarter after the date the definition is
adopted by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Compliance obligations for the Phase 2 definition would begin:
Twenty‐four months after the applicable effective date of the definition (for newly identified
Elements), or
If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case‐by‐case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Exhibit C
Redlined Comparison of Proposed Definition
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition will
go into effect shall become effective on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by or as otherwise made effective
pursuant to the definition shall begin 24 months after the laws of applicable effective date of the
definition. governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
TBDJanuary
25, 2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773‐A
Draft #2: Date
Final Ballot – November 2013
Page 1 of 4
Project 2010-17 Definition of Bulk Electric System (Phase 2)
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 whenwill be balloted in the proposed standard is
approved.same manner as a Reliability Standard. When the standardapproved definition becomes
effective, thesethe defined termsterm will be removed from the individual standard and added to the
Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded underby application of Exclusion E1 or E3.
I2 -– Generating resource(s) with gross individual nameplate rating greater than 20 MVA or
gross plant/facility aggregate nameplate rating greater than 75 MVA including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above. with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources withthat aggregate to a total capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing), and that are connected through a system
designed primarily for aggregatingdelivering such capacity, connected at to a common point of
connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
)b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Draft #2: Date
Final Ballot – November 2013
Page 2 of 4
Project 2010-17 Definition of Bulk Electric System (Phase 2)
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1. unless excluded by application of Exclusion E4.
Exclusions:
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in InclusionInclusions I2, I3,
or I4, with an aggregate capacity less than or equal to 75 MVA (gross nameplate
rating). Or,
c) Where the radial system serves Load and includes generation resources, not
identified in InclusionInclusions I2, I3 or I4, with an aggregate capacity of nonretail generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or above
100 kV but less than 300 kV that distribute power to Load rather than transfer bulk power
across the interconnected system. LN’s emanate from multiple points of connection at 100 kV
or higher to improve the level of service to retail customer Loadcustomers and not to
accommodate bulk power transfer across the interconnected system. The LN is characterized by
all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in InclusionInclusions I2, I3, or I4 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA
(gross nameplate rating) ;);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
Draft #2: Date
Final Ballot – November 2013
Page 3 of 4
Project 2010-17 Definition of Bulk Electric System (Phase 2)
c) Not part of a Flowgate or transfer path: The LN does not contain a monitored
Facilityany part of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored
Facility included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by installed for the sole benefit of a retail
customer solely for its own use.(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft #2: Date
Final Ballot – November 2013
Page 4 of 4
Exhibit D
White Paper on Bulk Electric System Radial Exclusion (E1) Low Voltage Loop Threshold- Public Version
PUBLIC VERSION
White Paper on Bulk Electric System
Radial Exclusion (E1) Low Voltage
Loop Threshold
September 2013
Project 2010‐17: Definition of Bulk Electric System
Table of Contents
Background ..................................................................................................................................... 1
Executive Summary ........................................................................................................................ 2
Step 1: Establishment of Minimum Monitored Regional Voltage Levels ................................... 3
Step 1 Conclusion .................................................................................................................... 6
Step 2: Load Flows and Technical Considerations ....................................................................... 7
Step 2 Conclusion .................................................................................................................. 16
Study Conclusion .......................................................................................................................... 17
Appendix 1: Regional Elements ................................................................................................... 18
Appendix 2: One‐Line Diagrams…………………………………………………………………………………………….. 19
Appendix 3: Simulation Results ................................................................................................... 21
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV .......................................... 32
Bulk Electric System Radial Exclusion (E1)
Low Voltage Loop Threshold
Background
The definition of “Bulk Electric System” (BES) in the NERC Glossary consists of a core definition and a list
of facilities configurations that will be included or excluded from the core definition. The core definition
is used to establish the bright line of 100 kV, the overall demarcation point between BES and non‐BES
elements. Exclusion E1 applies to radial systems. In Order No. 773 and 773‐A, the Federal Energy
Regulatory Commission’s (Commission or FERC) expressed concerns that facilities operating below 100
kV may be required to support the reliable operation of the interconnected transmission system. The
Commission also indicated that additional factors beyond impedance must be considered to
demonstrate that looped or networked connections operating below 100 kV need not be considered in
the application of Exclusion E1.1
This document responds to the Commission’s concerns and provides a technical justification for the
establishment of a voltage threshold below which sub‐100 kV equipment need not be considered in the
evaluation of Exclusion E1.
NOTE: This justification does not address whether sub‐ 100 kV systems should be evaluated as
Bulk Electrical System (BES) Facilities. Sub‐ 100 kV systems are already excluded from the BES
under the core definition. Order 773, paragraph 155 states: “Thus, the Commission, while
disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements
in figure 3 in the bulk electric system, unless determined otherwise in the exception process.”
This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the
Final Rule, the sub‐100 kV elements comprising radial systems and local networks will not be
included in the bulk electric system, unless determined otherwise in the exception process.” Sub‐
100 kV facilities will only be included as BES Facilities if justified under the NERC Rules of
Procedure (ROP) Appendix 5C Exception Process.
1
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure, Order No.
773, 141 FERC ¶ 61,236 at P155, n.139 (2012); order on reh’g, Order No. 773‐A, 143 FERC ¶ 61,053 (2013).
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 1
Executive Summary
The Project 2010‐17 Standard Drafting Team conducted a two‐step process to establish a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops do not affect the
application of Exclusion E1. The justification for establishing a lower voltage threshold for application of
Exclusion E1 consisted of a two‐step technical approach:
Step 1: A review was performed to determine the minimum voltage levels that are monitored
by Balancing Authorities, Reliability Coordinators, and Transmission Operators for Interfaces,
Paths, and Monitored Elements. This minimum voltage level reflects a value that industry
experts consider necessary to monitor and facilitate the operation of the Bulk Electric System
(BES). This step provided a technically sound approach to screen for a minimum voltage limit
that served as a starting point for the technical analysis performed in Step 2 of this study.
Step 2: Technical studies modeling the physics of loop flows through sub‐100 kV systems were
performed to establish which voltage level, while less than 100 kV, should be considered in the
evaluation of Exclusion E1.
The analysis establishes that a 50 kV threshold for sub‐100 kV loops does not affect the application of
Exclusion E1. This approach will ease the administrative burden on entities as it negates the necessity
for an entity to prove that they qualify for Exclusion E1 if the sub‐100 kV loop in question is less than or
equal to 50 kV. This analysis provides an equally effective and efficient alternative to address the
Commission’s directives expressed in Order No. 773 and 773‐A.
It should be noted that, although this study resulted in a technically justified 50 kV threshold based on
proven analytic methods, there are other preventative loop flow methods that entities can apply on
sub‐100 kV loop systems to address physical equipment concerns. These methods include:
Interlocked control schemes;
Reverse power schemes;
Transformer, feeder and bus tie protection; and
Custom protection and control schemes.
These methods are discussed in detail in Appendix 4. The presence of such equipment does not alter the
criteria developed in this white paper, nor does it influence the conclusions reached. Additionally, the
presence of this equipment does not remove or lessen an entity’s obligations associated with the bright‐
line application of the Bulk Electric System (BES) definition.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 2
Radial Systems Exclusion (E1)
The proposed definition (first posting) of radial systems in the Phase 2 BES Definition (Exclusion E1) was:
A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV
or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2 and I3, with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in
Inclusions I2 and I3, with an aggregate capacity of non‐retail generation less than or equal
to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on prints or
one‐line diagrams for example, does not affect this exclusion.
Note 2 ‐ The presence of a contiguous loop, operated at a voltage level of 30 kV or less2, between
configurations being considered as radial systems, does not affect this exclusion.
STEP 1 – Establishment of Minimum Monitored Regional Voltage Levels
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The groupings of these elements have different names: for instance,
Paths in the Western Interconnection; Interfaces or Flowgates in the Eastern Interconnection; or
Monitored Elements in the Electric Reliability Council of Texas (ERCOT). Nevertheless, they all constitute
element groupings that operating entities (Reliability Coordinators, Balancing Authorities, and
Transmission Operators) monitor because they understand that they are necessary to ensure the
reliable operation of the interconnected transmission system under diverse operating conditions.
To provide information in determining a voltage level where the presence of a contiguous loop between
system configurations may not affect the determination of radial systems under Exclusion E1 of the BES
definition, voltage levels that are monitored on major Interfaces, Flowgates, Paths, and ERCOT
Monitored Elements were examined. This examination focused on elements owned and operated by
entities in North America. The objective was to identify the lowest monitored voltage level on these key
element groupings. The lowest monitored line voltage on the major element groupings provides an
indication of the lower limit which operating entities have historically believed necessary to ensure the
2
The first posting of this Phase 2 definition used a threshold of 30 kV; however as a result of the study work described in
this paper, the Standard Drafting Team has revised the threshold to 50 kV for subsequent industry consideration.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 3
reliable operation of the interconnected transmission system. The results of this analysis provided a
starting point for the technical analysis which was performed in Step 2 of this study.
Step 1 Approach
Each Region was requested to provide the key groupings of elements they monitor to ensure reliable
operation of the interconnected transmission system. This list, contained in Appendix 1, was reviewed
to identify the lowest voltage element in the major element groupings monitored by operating entities
in the eight Regions. Identification of this lowest voltage level served as a starting point to begin a
closer examination into the voltage level where the presence of a contiguous loop should not affect the
evaluation of radial systems under Exclusion E1 of the BES definition.
Step 1 Results
An examination of the line listings of the North American operating entities revealed that the majority of
operating entities do not monitor elements below 69 kV as shown in Table 1. However, in some
instances elements with line voltages of 34.5 kV were included in monitored element groupings. In no
instance was a transmission line element below 34.5 kV included in the monitored element groupings.
Region
Key Monitored Element Grouping
Lowest Line Element Voltage
FRCC
Southern Interface
115
MRO
NDEX
69
Total East PJM (Rockland Electric) – Hudson Valley
NPCC
34.5
(Zone G)1
RFC
MWEX
69
SERC
VACAR IDC2
100
SPP RE
SPSNORTH_STH
115
TRE
Valley Import GTL
138
WECC
Path 52 Silver Peak – Control 55 kV
55
Notes:
1. Two interfaces in NPCC/NYISO have lines with 34.5 kV elements.
2. The TVA area in SERC was not included in the tables attached to this report; however, a review of the
Flowgates in TVA revealed monitored elements no lower than 115 kV. There were a number of
Flowgates with 115 kV monitored elements in SERC, the monitored grouping listed is representative.
Table 1: Lowest Line Element Voltage Monitored by Region
In a few rare occasions there were transformer elements with low‐side windings lower than 30 kV included in
the key monitored element groupings as shown in Table 2.
Region
Interface
Element
Voltage (kV)
NPCC/NYISO
WEST CENTRAL: Genesee (Zone
B) – Central (Zone C)
New England ‐ Southwest
Connecticut
NPCC/ISO‐NE
(Farmtn 34.5/115kV&12/115 kV) #4
34.5/115 & 12/115
SOTHNGTN 5X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐5X)
SOTHNGTN 6X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐6X)
SOTHNGTN 11X ‐ Southington 115 kV
/27.6 kV Transformer (4C‐11X)
12/115
115/13.8
115/13.8
115/27.6
Table 2: Lowest Line Transformer Element Voltages Monitored by Region
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 4
Upon closer investigation, for New England’s Southwest Connecticut interface, it was determined that
the inclusion of these elements was the result of longstanding, historical interface definitions and not
for the purpose of addressing BES reliability concerns. Transformers serving lower voltage networks
continue to be included based on familiarity with the existing interface rather than a specific technical
concern. These transformers could be removed from the interface definition with no impact on
monitoring the reliability of the interconnected transmission system. For the New York West Central
interface, the low voltage element was included because the interface definition included boundary
transmission lines between Transmission Owner control areas; hence, it was included for completeness
to measure the power flow from one Transmission Owner control area to the other Transmission Owner
control area.
Further examination of the information provided by the eight NERC regions revealed that half of the
Regions only monitor transmission line elements with voltages above the 100 kV level. The other four
Regions, NPCC, RFC, MRO, and WECC, monitor transmission line elements below 100 kV as part of key
element groupings. However, in each of these cases, the number of below 100 kV transmission line
elements comprised less than 2.5% of the total monitored key element groupings. Figures 1 and 2
below depict the results of Step 1 of this study.
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 1: Voltage as Percent of Monitored Elements
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 5
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 2: Voltage as Percent of Monitored Elements per Region
Step 1 Conclusion
The results of Step 1 of this study regarding regional monitoring levels resulted in a determination that
30 kV was a reasonable voltage level to initiate the sensitivity analysis conducted in Step 2 of this study.
This value is below any of the regional monitoring levels. As noted herein, an examination of the line
listings of the North American operating entities revealed that the majority of operating entities do not
monitor elements below 69 kV as shown in Table 1. However, in some instances elements with line
voltages of 34.5 kV were included in monitored element groupings. In no instance was a transmission
line element below 34.5 kV included in the monitored element groupings.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 6
STEP 2 ‐ Load Flows and Technical Considerations
The threshold of 30 kV was established in Step 1 as a reasonable starting point to initiate the technical
sensitivity analysis performed in Step 2 of this study. The purpose of this step was to determine if there
is a technical justification to support a voltage threshold for the purpose of determining whether
facilities greater than 100 kV can be considered to be radial under the BES Definition Exclusion E1. If the
resulting voltage threshold was deemed appropriate through technical study efforts, then contiguous
loop connections operated at voltages below this value would not preclude the application of Exclusion
E1. Conversely, contiguous loops connecting radial lines at voltages above this kV value would negate
the ability for an entity to use Exclusion E1 for the subject facilities.
This study focused on two typical configurations: a distribution loop and a sub‐transmission loop. The
study evaluated a range of voltages for the loop and the parallel transmission system with the goal of
determining the voltage level below which single contingencies on the transmission system would not
result in power flow from a low voltage distribution or sub‐transmission loop to the BES. The study
included sensitivity analysis varying the loads and impedances. Variations in loop and transmission
system impedances account for a range of physical parameters such as conductor length, conductor
type, system configuration, and proximity of the loop to the transmission system. This study provided
the low voltage floor that can be used as a consideration for BES exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 7
Analytical Approach – Distribution Circuit Loop Example
The Project 2010‐17 Standard Drafting Team sought to examine the interaction and relative magnitude
of flows on the 100 kV and above Facilities of the electric system and those of any underlying low
voltage distribution loops. While not the determining factor leading to this study’s recommendation,
line outage distribution factors (LODF) were a useful tool in understanding the relationship between
underlying systems and the BES elements. It illustrated the relative scale of interaction between the BES
and the lower voltage systems and its review was a consideration when this study was performed. As
an example, the Standard Drafting Team considered a system similar to the one depicted in Figure 3
below. In this simplified depiction of a portion of an electric system, two radial 115 kV lines emanate
from 115 kV substations A and B to serve distribution loads via 115 kV distribution transformers at
stations C and D. Stations C and D are “looped” together via either a distribution bus tie (zero
impedance) or a feeder tie (modeled with typical distribution feeder impedances).
Figure 3: Example Radial Systems with Low Voltage Distribution Loop
With the example system, the Standard Drafting Team conducted power flow simulations to assess the
performance of the power system under single contingency outages of the line between stations A and
B. The analyses determined the LODF which represent the portion of the high voltage transmission flow
that would flow across the low voltage distribution circuit or bus ties under a single contingency outage
of the line between stations A and B. To the extent that the LODF values were negligible, this indicated a
minor or insignificant contribution of the distribution loops to the operation of the high voltage system.
But, more importantly, the analyses determined whether any instances of power flow reversal, i.e.,
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 8
resultant flow delivered into the BES, would occur during contingent operating scenarios. Instances of
flow reversal into the BES would indicate that the underlying distribution looped system is exhibiting
behavior similar to a sub‐transmission or transmission system, which would call into question the
applicability of radial exclusion E1.
The study work in this approach examined the sensitivity of parallel circuit flow on the distribution
elements to the size of the distribution transformers, the operating voltage of distribution delivery buses
at stations C and D and the strength of the transmission network serving stations A and B as manifested
in the variation of the transmission network transfer impedances used in the model.
In order to simply, yet accurately, represent this low voltage loop scenario between two radial circuits, a
Power System Simulator for Engineering (PSSE) model was created. Elements represented in this model
included the following:
Radial 115 kV lines from station A to station C and station B to station D;
Interconnecting transmission line from station A to station B;
Distribution transformers tapped off the 115 kV lines between stations A and C and between
stations B and D and at stations C and D;
Feeder tie impedance to represent a feeder tie (or zero impedance bus tie) between distribution
buses at stations C and D;
Transfer impedance equivalent between stations A and B, representing the strength of the
interconnected transmission network3.
Within this model, parameters were modified to simulate differences in the length and impedance of
the transmission lines, the amount of distribution load, the strength of the transmission network
supplying stations A and B, the size of the distribution transformers and the character of the bus or
feeder ties at distribution Stations C and D.
Distribution Model Simulation
Table 3 below illustrates the domain of the various parameters that were simulated in this distribution
circuit loop scenario. A parametric analysis was performed using all combinations of variables shown in
each column of the upper portion of Table 3. Sensitivity analysis was performed as indicated in the
lower portion of the table.
3
The relative strength of the surrounding transmission system network is a function of the quantity of parallel
transmission paths and the impedance of those paths between the two source substations. A high number of parallel
paths with low impedance translates to a low transfer impedance, which allows power to more readily flow between the
stations. Conversely, a low number of parallel paths having higher impedance is represented by a relatively large
transfer impedance.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 9
Trans KV
Trans Length
115
10 miles
Sensitivity Analysis:
Dist KV
Dist Length
XFMR MVA
12.5
23
34.5
46
0 (bus tie)
2 miles
5 miles
10
20
40
Dist Load % Z Transfer
rating
40
Weak
80
Strong
Medium
Notes:
1. The “medium” value for transfer impedances was derived from an actual example system in the
northeastern US. This was deemed to be representative of a network with typical, or medium,
transmission strength. Variations of a stronger (more tightly coupled) and a weaker transmission network
were selected for the “strong” and “weak” cases, respectively. Impedance values of X=0.54%, X=1.95%,
and X=4.07% were applied for the strong, medium and weak cases, respectively.
Table 3: Model Parameters Varied
The model was used to examine a series of cases simulating a power transfer on the 115 kV line4 from
station A to station B of slightly more than 100 MW. Loads and impedances were simulated at the
location shown in Figure 5 of Appendix 2. Two load levels were used in each scenario: 40% of the rating
of the distribution transformer and 80% of the rating. Distribution transformer ratings were varied in
three steps: 10 MVA, 20 MVA, and 40 MVA. Finally, the strength of the interconnected transmission
network was varied in three steps representing a strong, medium, and weak transmission network. The
choices of transfer impedance were based on typical networks in use across North America. A specific
model from the New England area of the United States yielded an actual transfer impedance of 0.319 +
j1.954%. This represents the ’medium’ strength transmission system used in the analyses. The other
values used in the study are minimum (’strong’) and maximum (’weak’) ends of the typical range of
transfer impedances for 115 kV systems interconnected to the Bulk Electric System of North America.
Distribution feeder connections were simulated in three different ways, first with zero impedance
between the distribution buses at stations C and D, second with a 2‐mile feeder connection with typical
overhead conductor, and third with a 5‐mile connection.
Distribution Model Results
23 kV Distribution System
The results show LODFs ranging from a low of 0.2% to a high of 6.7%. In all of the cases, the direction of
power flow to the radial lines at stations A and B was toward stations C and D. In other words, there
were no instances of flow reversal from the distribution system back to the 115 kV transmission system.
The lowest LODF was found in the case with the smallest distribution transformers (10 MVA), the 5‐mile
distribution circuit tie, and the strong transmission transfer impedance. The case with the highest LODF
4
The threshold voltage of 115 kV provides conservative results. At a higher voltage, such as 230 kV, the reflection of
distribution impedance to the transmission system is significantly larger, and hence, the amount of distribution power
flow will be much smaller.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 10
was that which used the largest distribution transformers (40 MVA) with the lightest load and the use of
a zero‐impedance bus tie between the two distribution stations.
12.5 kV Distribution System
As compared to the simulations using the 23 kV distribution system, the 12.5 kV system model yielded
far lower LODF values. This result is reasonable, as the reflection of impedances on a 12.5 kV
distribution system will be nearly four times as large as those for a 23 kV distribution system, and the
transformer sizes in use at the 12.5 kV class are generally smaller, i.e., higher impedance. As with the
cases simulated for the 23 kV system, the 12.5 kV system exhibited a power flow direction in the radial
line terminals at stations A and B in the direction of the distribution stations C and D; no flow reversal
was seen in any of the contingency cases.
Given the lower voltage of the distribution system, the cases studied at this low voltage level were
limited to the scenario with the high transfer impedance value (’weak’ transmission case). This is a
conservative assumption as all cases with lower transfer impedance will yield far lower LODF values.
With that, the range of LODF values was found to be 1.0% to 6.7%. When compared with the 23 kV
system results in the weak transmission case, the range of LODF values was 1.8% to 6.7%. Higher LODF
values were found in the cases with the largest transformer size, which is to be expected.
Table 4 below provides a sample of the results of the various simulations that were conducted. The full
collection of results is provided in Appendix 3.
Case
D, KV
623a5
623a5pk
633b0pk
723c0
723c5pk
823b0
823c0
812a5
812b0
812b5pk
812c0
834a5pk
834b5pk
834d0
834d0pk
846e0
846e2
846e5
23
23
23
23
23
23
23
12.5
12.5
12.5
12.5
34.5
34.5
34.5
34.5
46
46
46
Z xfer
strong
strong
strong
medium
medium
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
ZDist
5 mi
5 mi
0
0
5 mi
0
0
5 mi
0
5 mi
0
5 mi
5 mi
0
0
0
2 mi
5 mi
XFMR MVA
Load, MW
LODF
10
10
20
40
40
20
40
10
20
20
40
10
20
40
40
50
50
50
4
8
16
16
32
8
16
4
8
16
16
8
16
16
32
16
20
20
0.2%
0.3%
0.4%
3.4%
1.6%
3.8%
6.7%
1.0%
3.8%
1.3%
6.7%
1.7%
3.0%
8.9%
8.7%
10.3%
9.0%
7.4%
Table 4: Select Sample of Study Results for Distribution Scenario
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 11
34.5 kV and 46 kV Distribution Systems
As with the analysis done for the 12.5 kV system, a conservative transfer impedance value, that of the
’weak’ transmission network, was used in selecting the transfer impedance to be used in the simulations
at 34.5 kV and 46 kV. With this conservative parameter, the simulation results show distribution factors
(LODF) ranging from a low of 1.7% to a high of 10.3%. In all of the cases, the direction of power flow to
the radial lines remained from stations A and B toward stations C and D. In other words, there were no
instances of flow reversal from the distribution system back to the 115 kV transmission system.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 12
Analytical Approach – Sub‐transmission Example
In addition to the distribution circuit loop example described above, the study examined the
performance of systems typically described as ’sub‐transmission.’ The study sought to examine the
interaction and relative magnitude of flows on the 100 kV and above Facilities of the interconnected
transmission system and those of the underlying parallel sub‐transmission facilities. The study
considered a system similar to the one depicted in Figure 4 below. In this simplified depiction of a
portion of a transmission and sub‐transmission system, a 40‐mile transmission line connecting two
sources with transfer impedance between the two sources representing the parallel transmission
network. Each source also supplies a 10‐mile transmission line with a load tap at the mid‐point of the
line, each serving a load of 16 MW. At the end of each of these lines is a step‐down transformer to the
sub‐transmission voltage, where an additional load is served. The two sub‐transmission stations are
connected by a 25‐mile sub‐transmission tie line. Loads and impedances were simulated at the location
shown in Figure 6 of Appendix 2.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 13
Figure 4: Example Radial Systems with Sub‐transmission Loop
Given this example sub‐transmission system, a PSSE model was created to simulate the power flow
characteristics of the system during a contingency outage of the transmission line between stations A
and B. Within this model, parameters were modified to simulate differences in the amount of load
being served, transformer size and the amount of pre‐contingent power flow on the transmission line.
All simulations were performed with a transfer impedance representative of a ‘weak’ transmission
network, which was confirmed as conservative in the distribution system analysis.
Sub‐transmission Model Simulation
Simulations were performed for each sub‐transmission voltage (34.5 kV, 46 kV, 55 kV, and 69 kV) using a
transmission voltage of 115 kV. This analysis identified the potential for power flowing back to the
transmission system only for sub‐transmission voltages of 55 kV and 69 kV. Sensitivity analysis was
performed using higher transmission voltages to confirm that cases modeling a 115 kV transmission
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 14
system yield the most conservative results. Therefore, it was not necessary to perform sensitivity
analysis for sub‐transmission voltages of 34.5 kV and 46 kV for transmission voltages higher than 115 kV.
Table 5 below illustrates the domain of the various parameters that were simulated in this sub‐
transmission circuit loop scenario. A parametric analysis was performed using combinations of variables
shown in each column of Table 5.
Trans KV
Trans Length Sub‐T KV
Sub‐T Length XFMR MVA
Dist Load
Trans MW
% rating
Preload
115
40 miles
34.5
25 miles
40
40
115
46
50
55
60
69
Sensitivity Analyses:
138
40 miles
55
25 miles
50
40
115
161
69
60
135
230
150
220
Table 5: Model Parameters and Sensitivities
Sub‐transmission Model Results
115 kV Transmission System with 34.5‐69 kV Sub‐transmission
The results for cases depicting a 115 kV transmission system voltage and ranges of 34.5 kV to 69 kV sub‐
transmission voltages show line outage distribution factors (LODF) in the range of 9% to slightly higher
than 20%. Several cases show a reversal of power flow in the post‐contingent system such that power
flow is delivered from the sub‐transmission system into the 115 kV BES. The worst case is found in the
69 kV sub‐transmission voltage class. This result is as expected, given that the impedance of the 69 kV
sub‐transmission system is less than the impedances of lower voltage systems. In no instance was a
reversal of power flow observed in sub‐transmission systems rated below 50 kV.
138 kV and 161 kV Transmission Systems with 55‐69 kV Sub‐transmission
The results for cases of 138 kV and 161 kV transmission system voltages supplying sub‐transmission
voltages of 55 kV and 69 kV show LODFs ranging from 9% to 16%. These cases also result in reversal of
power flows in the post‐contingent system such that power flow is delivered from the sub‐transmission
system into the 115 kV BES.
230 kV Transmission System with 55‐69 kV Sub‐transmission
By simulating a higher BES source voltage of 230 kV paired with sub‐transmission voltages of 55 kV and
69 kV, the transformation ratio is sufficiently large to result in a significant increase to the reflected sub‐
transmission system impedance. Therefore, in these cases, LODFs range from 5% to 7%, and these cases
also show no reversal of power flow toward the BES in the post‐contingent system. Table 6 below
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 15
provides a sample of the results of the various simulations that were conducted. All results are provided
in Appendix 3.
Case
T, KV
S‐T, KV
834d25
846e25
855e25
869f25
855e25‐138
855e25‐138’
869f25‐138
869f25‐138’
855e25‐161
855e25‐161’
869f25‐161
869f25‐161’
855e25‐230
855e25‐230’
869f25‐230
869f25‐230’
115
115
115
115
138
138
138
138
161
161
161
161
230
230
230
230
34.5
46
55
69
55
55
69
69
55
55
69
69
55
55
69
69
Trans Pre‐
load, MW
115
114
112
110
114
134
112
132
114
155
113
153
116
219
116
218
XFMR MVA
Load, MW
LODF
40
50
50
60
50
60
60
60
50
60
60
60
50
60
60
60
20
20
20
24
20
20
24
24
20
20
24
24
20
20
24
24
9.4%
13.3%
15.7%
20.3%
11.7%
11.9%
15.6%
15.8%
9.1%
9.2%
12.5%
12.6%
4.9%
5.0%
7.0%
7.0%
Flow Rev
to BES?
Yes
Yes
Yes
Yes
Yes
Yes
Table 6: Select Sample of Study Results for Sub‐transmission Scenario
Step 2 Conclusion
After conducting extensive simulations (included in Appendix 3), the results of Step 2 of this analysis
indicates that 50 kV is the appropriate low voltage loop threshold below which sub‐100 kV loops should
not affect the application of Exclusion E1 of the BES Definition. Simulations of power flows for the cases
modeled in this study show there is no power flow reversal into the BES when circuit loop operating
voltages are below 50 kV. This study also finds, for loop voltages above 50 kV, certain cases result in
power flow toward the BES. Therefore, the study concludes that low voltage circuit loops operated
below 50 kV should not affect the application of Exclusion E1.
As described throughout the preceding section, the scenarios and configurations utilized in this analysis
represent the majority of cases that will be encountered in the industry. The models used in this
analysis establish reasonable bounds and use conservative parameters in the scenarios. However, there
may be actual cases that deviate from these modeled scenarios, and therefore, results could be
somewhat different than the ranges of results from this analysis. Such deviations are expected to be
rare and can be processed through the companion BES Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 16
Study Conclusion
The Project 2010‐17 Standard Drafting Team conducted a two‐step study process to yield a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops should not affect
the application of Exclusion E1.
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The objective of Step 1 was to identify the lowest monitored voltage
level on these key element groupings. The lowest monitored line voltage on the major element
groupings provides an indication of the lower limit which operating entities have historically believed
necessary to ensure the reliable operation of the interconnected transmission system.
As a result of studying such regional monitoring levels, Step 1 concluded that 30 kV was a reasonable
voltage level to initiate the sensitivity analysis conducted in Step 2. This is a conservative value as it is
below any of the regional monitoring levels.
Using the conservative value established by Step 1, the Standard Drafting Team conducted extensive
simulations of power flows which demonstrated that there is no power flow reversal into the BES when
circuit loop operating voltages are below 50 kV. Therefore, the study concludes that low voltage circuit
loops operated below 50 kV should not affect the application of Exclusion E1. This analysis provides an
equally effective and efficient alternative to address the Commission’s directives expressed in Order No.
773 and 773‐A.
The scenarios and configurations utilized in this analysis represent the majority of cases that will be
encountered in the industry. The models used in this analysis establish reasonable bounds and use
conservative parameters in the scenarios. However, there may be actual cases that deviate from these
modeled scenarios, and therefore, results could be somewhat different than the ranges of results from
this analysis. Such deviations are expected to be rare and can be processed through the companion BES
Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 17
Appendix 1: Regional Elements
PRIVILEGED AND CONFIDENTIAL INFORMATION HAS BEEN REDACTED FROM THIS PUBLIC VERSION
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 18
Appendix 2: One‐Line Diagrams
Note: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Figure 5: Example Radial Systems with Low Voltage Distribution Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 19
Notes: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Step‐down transformers from sub‐transmission voltage to distribution voltage were not explicitly
modeled in the simulations.
Figure 6: Example Radial Systems with Sub‐transmission Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 20
Appendix 3: Simulation Results
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
23 kV Base Cases
623a0
10
Strong
15
0
10%/10
10%/10
4.0
4.0
110.7
10.9
6.9
1.1
5.1
11.2
7.2
0.8
4.8
0.003
623a2
10
Strong
15
2
10%/10
10%/10
4.0
4.0
110.7
10.7
6.7
1.4
5.4
10.9
6.9
1.1
5.1
0.002
623a5
10
Strong
15
5
10%/10
10%/10
4.0
4.0
110.7
10.3
6.3
1.7
5.7
10.5
6.5
1.5
5.5
0.002
623a0pk
10
Strong
15
0
10%/10
10%/10
8.0
8.0
111.4
19.0
10.9
5.1
13.1
19.3
11.2
4.8
12.8
0.003
623a2pk
10
Strong
15
2
10%/10
10%/10
8.0
8.0
111.4
18.7
10.7
5.4
13.4
18.9
10.9
5.1
13.1
0.002
623a5pk
10
Strong
15
5
10%/10
10%/10
8.0
8.0
111.5
18.3
10.3
5.7
13.7
18.6
10.5
5.5
13.5
0.003
623b0
10
Strong
15
0
10%/20
10%/20
8.0
8.0
111.1
21.7
13.7
2.3
10.3
22.3
14.2
1.8
9.8
0.005
623b2
10
Strong
15
2
10%/20
10%/20
8.0
8.0
111.2
20.7
12.7
3.3
11.3
21.2
13.2
2.9
10.9
0.004
623b5
10
Strong
15
5
10%/20
10%/20
8.0
8.0
111.3
19.7
11.7
4.3
12.3
20.1
12.1
4.0
12.0
0.004
623b0pk
10
Strong
15
0
10%/20
10%/20
16.0
16.0
112.6
37.8
21.7
10.3
26.3
38.3
22.3
9.7
25.8
0.004
623b2pk
10
Strong
15
2
10%/20
10%/20
16.0
16.0
112.7
36.7
20.7
11.3
27.3
37.2
21.2
10.9
26.9
0.004
623b5pk
10
Strong
15
5
10%/20
10%/20
16.0
16.0
112.8
35.7
19.7
12.3
28.4
36.1
20.1
12.0
28.0
0.004
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 21
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
623c0
10
Strong
15
0
10%/40
10%/40
16.0
16.0
112.2
42.7
26.6
5.4
21.4
43.7
27.7
4.3
20.3
0.009
623c2
10
Strong
15
2
10%/40
10%/40
16.0
16.0
112.5
39.6
23.6
8.4
24.4
40.4
24.4
7.7
23.7
0.007
623c5
10
Strong
15
5
10%/40
10%/40
16.0
16.0
112.7
37.3
21.3
10.8
26.8
37.8
21.8
10.3
26.3
0.004
LODF
623c0pk
10
Strong
15
0
10%/40
10%/40
32.0
32.0
115.1
74.9
42.8
21.2
53.3
76.0
43.9
20.2
52.2
0.010
623c2pk
10
Strong
15
2
10%/40
10%/40
32.0
32.0
115.4
71.8
39.7
24.3
56.4
72.6
40.5
23.6
55.6
0.007
623c5pk
10
Strong
15
5
10%/40
10%/40
32.0
32.0
115.6
69.4
37.4
26.7
58.8
70.0
37.9
26.2
58.3
0.005
723a0
10
Medium
15
0
10%/10
10%/10
4.0
4.0
108.3
10.9
6.9
1.1
5.1
11.9
7.9
0.1
4.1
0.009
723a2
10
Medium
15
2
10%/10
10%/10
4.0
4.0
108.3
10.6
6.6
1.4
5.4
11.5
7.5
0.5
4.5
0.008
723a5
10
Medium
15
5
10%/10
10%/10
4.0
4.0
108.4
10.3
6.3
1.8
5.8
11.1
7.1
1.0
5.0
0.007
723a0pk
10
Medium
15
0
10%/10
10%/10
8.0
8.0
110.4
18.9
10.9
5.1
13.1
20.0
12.0
4.0
12.1
0.010
723a2pk
10
Medium
15
2
10%/10
10%/10
8.0
8.0
110.5
18.6
10.6
5.4
13.4
19.6
11.6
4.4
12.5
0.009
723a5pk
10
Medium
15
5
10%/10
10%/10
8.0
8.0
110.6
18.3
10.3
5.7
13.7
19.1
11.1
4.9
12.9
0.007
723b0
10
Medium
15
0
10%/20
10%/20
8.0
8.0
109.7
21.6
13.6
2.4
10.4
23.6
15.6
0.4
8.4
0.018
723b2
10
Medium
15
2
10%/20
10%/20
8.0
8.0
110.0
20.6
12.6
3.4
11.4
22.3
14.3
1.7
9.8
0.015
723b5
10
Medium
15
5
10%/20
10%/20
8.0
8.0
110.2
19.7
11.7
4.4
12.4
21.0
13.0
3.1
11.1
0.012
723b0pk
10
Medium
15
0
10%/20
10%/20
16.0
16.0
114.0
37.8
21.8
10.2
26.3
39.9
23.8
8.2
24.2
0.018
723b2pk
10
Medium
15
2
10%/20
10%/20
16.0
16.0
114.3
36.8
20.8
11.3
27.3
38.5
22.5
9.6
25.6
0.015
723b5pk
10
Medium
15
5
10%/20
10%/20
16.0
16.0
114.5
35.8
19.8
12.3
28.3
37.2
21.1
10.9
27.0
0.012
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 22
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
723c0
10
Medium
15
0
10%/40
10%/40
16.0
16.0
112.6
42.7
26.7
5.3
21.3
46.5
31.4
1.6
17.6
0.034
723c2
10
Medium
15
2
10%/40
10%/40
16.0
16.0
113.5
39.7
23.7
8.4
24.4
42.4
26.4
5.7
21.7
0.024
723c5
10
Medium
15
5
10%/40
10%/40
16.0
16.0
114.1
37.4
21.4
10.7
26.7
39.3
23.3
8.8
24.8
0.017
723c0pk
10
Medium
15
0
10%/40
10%/40
32.0
32.0
121.2
75.5
43.4
20.7
52.7
79.5
47.4
16.7
48.7
0.033
723c2pk
10
Medium
15
2
10%/40
10%/40
32.0
32.0
122.0
72.2
40.1
23.9
55.9
75.2
43.1
21.1
53.1
0.025
723c5pk
10
Medium
15
5
10%/40
10%/40
32.0
32.0
122.7
69.8
37.7
26.4
58.5
71.8
39.7
24.4
56.5
0.016
823a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
823a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
823a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.4
10.2
62.0
1.8
5.8
11.9
7.9
0.2
4.2
0.016
823a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
823a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.6
12.6
3.5
11.5
0.018
823a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.8
18.3
10.3
5.7
13.8
20.0
12.0
4.0
12.1
0.015
823b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
823b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.8
20.6
12.6
3.4
11.4
24.0
16.0
0.1
8.1
0.031
823b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
109.2
19.6
11.6
4.4
12.4
22.3
14.3
1.8
9.8
0.025
823b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
823b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.7
36.9
20.8
11.2
27.2
40.4
24.4
7.7
23.7
0.030
823b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
116.2
35.9
19.8
12.2
28.2
38.7
22.7
9.4
25.5
0.024
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 23
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
823c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
823c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
114.4
39.7
23.7
8.3
24.3
45.4
29.3
2.8
18.8
0.050
823c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
115.5
37.4
21.4
10.6
26.7
41.4
25.4
6.8
22.8
0.035
823c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
823c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
128.2
72.7
40.6
23.5
55.6
78.9
48.6
17.4
49.5
0.048
823c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
129.3
70.1
38.0
26.1
58.2
74.5
42.4
21.8
53.9
0.034
Sensitivity to Length of Lines 1‐4
723a0_30
10
Medium
30
0
10%/10
10%/10
4.0
4.0
108.3
10.8
6.8
1.2
5.2
11.8
7.8
0.2
4.2
0.009
723a2_30
10
Medium
30
2
10%/10
10%/10
4.0
4.0
108.4
10.5
6.5
1.5
5.5
11.4
7.4
0.6
4.6
0.008
723a5_30
10
Medium
30
5
10%/10
10%/10
4.0
4.0
108.5
10.2
6.2
1.8
5.8
11.0
7.0
1.0
5.0
0.007
Selected 34.5 kV cases
834a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
834a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.1
10.7
6.7
1.3
5.3
12.7
8.7
‐0.7
3.3
0.019
834a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
834a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
834a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.6
18.8
10.8
5.2
13.3
20.8
12.8
3.2
11.2
0.018
834a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.5
12.5
3.5
11.5
0.017
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
834b0
10
Weak
15
0
10%/20
10%/20
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 24
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
834b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.6
21.1
13.1
2.9
10.9
24.8
16.8
‐0.7
7.3
0.034
834b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
108.9
20.5
12.5
3.5
11.5
23.8
15.8
0.3
8.3
0.030
LODF
834b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
834b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.5
37.4
21.4
10.7
26.7
41.3
25.3
6.8
22.8
0.034
834b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
115.8
36.8
20.7
11.3
27.3
40.3
24.2
7.8
23.9
0.030
834c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
834c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
113.8
41.2
25.2
6.9
22.9
47.8
31.7
0.4
16.4
0.058
834c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
114.6
39.5
23.5
8.5
24.6
45.0
29.0
3.2
19.2
0.048
834c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
834c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
127.5
74.2
42.1
21.9
54.0
81.5
49.4
14.7
46.8
0.057
834c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
128.3
72.4
40.3
23.8
55.8
78.5
46.4
17.9
49.9
0.048
834d0
10
Weak
15
0
7%/40
7%/40
16.0
16.0
111.6
46.3
30.3
1.7
17.7
56.2
40.1
‐8.1
7.9
0.089
834d2
10
Weak
15
2
7%/40
7%/40
16.0
16.0
112.8
43.6
27.6
4.4
20.4
51.8
35.8
‐3.6
12.4
0.073
834d5
10
Weak
15
5
7%/40
7%/40
16.0
16.0
113.9
41.1
25.1
7.0
23.0
47.6
31.6
0.6
16.6
0.057
834d0pk
10
Weak
15
0
7%/40
7%/40
32.0
32.0
124.9
80.0
47.9
16.2
48.2
90.9
58.8
5.3
37.3
0.087
834d2pk
10
Weak
15
2
7%/40
7%/40
32.0
32.0
126.3
77.0
44.9
19.2
51.2
86.1
54.0
10.2
42.2
0.072
834d5pk
10
Weak
15
5
7%/40
7%/40
32.0
32.0
127.5
74.2
42.1
22.0
54.1
81.4
49.3
15.0
47.0
0.056
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 25
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
Selected 12.47 kV cases
812a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
812a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.4
10.1
6.1
1.9
5.9
11.6
7.6
0.4
4.4
0.014
812a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.7
9.4
5.4
2.6
6.6
10.5
6.5
1.5
5.5
0.010
812a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
812a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.9
18.1
10.1
5.9
13.9
19.7
11.7
4.3
12.4
0.015
812a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
110.2
17.5
9.5
6.5
14.5
18.6
10.6
5.5
13.5
0.010
812b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
812b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
109.4
19.2
11.2
4.8
12.8
21.7
13.6
2.5
10.5
0.023
812b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
110.0
17.9
9.9
6.1
14.1
19.4
11.4
4.7
12.7
0.014
812b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
812b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
116.4
35.4
19.4
12.6
28.6
38.0
22.0
10.2
26.2
0.022
812b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
117.0
34.1
18.0
14.0
30.0
35.6
19.6
12.6
28.6
0.013
812c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
812c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
115.9
36.6
20.6
11.5
27.5
40.0
24.0
8.3
24.3
0.029
812c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
116.8
34.4
18.4
13.7
29.7
36.2
20.2
12.0
28.0
0.015
812c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
812c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
129.7
69.2
37.1
27.1
59.1
73.0
40.9
23.5
55.5
0.029
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 26
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
10
Weak
15
5
10%/40
10%/40
32.0
32.0
130.8
66.7
34.7
29.4
61.5
68.8
36.7
27.6
59.6
0.016
846e0
10
Weak
15
0
10%/40
7%/50
16.0
20.0
112.1
53.1
37.1
2.9
18.9
64.7
48.7
‐8.6
7.4
0.103
846e2
10
Weak
15
2
10%/40
7%/50
16.0
20.0
113.2
50.7
34.7
5.3
21.3
60.9
44.8
‐4.7
11.3
0.090
846e5
10
Weak
15
5
10%/40
7%/50
16.0
20.0
114.3
48.2
32.1
7.9
24.0
56.7
40.7
‐0.4
15.6
0.074
669f25
40
Strong
20
25
10%/40
7%/60
16.0
24.0
114.0
76.0
59.8
‐10.8
5.2
79.6
63.4
‐14.2
1.8
0.032
769f25
40
Medium
20
25
10%/40
7%/60
16.0
24.0
111.7
75.3
59.1
‐10.1
5.9
87.3
71.0
‐21.2
‐5.2
0.107
869f25
40
Weak
20
25
10%/40
7%/60
16.0
24.0
109.8
74.7
58.5
‐9.6
6.4
97.0
80.6
‐30.0
‐14.0
0.203
812c5pk
LODF
Selected 46 kV cases
Sub‐transmission cases
115‐69 kV
115‐55 kV
655e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
114.5
62.1
46.0
‐5.0
11.0
64.8
48.7
‐7.5
8.5
0.024
755e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
113.3
61.8
45.7
‐4.8
11.2
70.9
54.8
‐13.0
3.0
0.080
855e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
112.1
61.5
45.4
‐4.5
11.5
79.1
62.9
‐20.2
‐4.2
0.157
855f25
115‐46 kV
646e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
115.0
57.3
41.2
‐0.2
15.8
59.5
43.4
‐2.1
13.9
0.019
746e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
114.6
57.2
41.2
‐0.1
15.9
64.9
48.8
‐6.8
9.2
0.067
846e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.2
57.2
41.1
0.0
16.0
72.4
56.2
‐13.1
2.9
0.133
40
Strong
20
25
10%/40
7%/40
16.0
16.0
115.3
46.2
30.2
2.6
18.7
47.7
31.7
1.4
17.4
0.013
115‐34.5 kV
634d25
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 27
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
734d25
40
Medium
20
25
10%/40
7%/40
16.0
16.0
115.4
46.3
30.2
2.6
18.6
51.5
35.5
‐1.9
14.1
0.045
834d25
40
Weak
20
25
10%/40
7%/40
16.0
16.0
115.5
46.3
30.2
2.6
18.6
57.1
41.0
‐6.4
9.6
0.094
869f25‐138
40
Weak
20
25
10%/40
7%/60
16.0
24.0
112.0
66.5
50.4
‐1.8
14.2
84.0
67.9
‐18.3
‐2.3
0.156
869f25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
131.9
71.1
55.0
‐6.3
9.8
92.0
75.8
‐25.6
‐9.6
0.158
LODF
138‐69 kV
138‐55 kV
855e25‐138
40
Weak
20
25
10%/40
7%/50
16.0
20.0
113.5
55.1
39.0
1.5
17.5
68.4
52.3
‐10.8
5.2
0.117
855e25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
134.0
58.5
42.4
‐1.7
14.3
74.4
58.3
‐16.2
‐0.2
0.119
869f25‐161
40
Weak
20
25
10%/40
7%/60
16.0
24.0
113.2
60.7
44.7
3.7
19.7
74.8
58.8
‐9.8
6.2
0.125
869f25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
153.0
68.0
52.0
‐3.3
12.7
87.3
71.2
‐21.4
‐5.4
0.126
855e25‐161
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.1
50.7
34.7
5.6
21.6
61.1
45.1
‐4.2
11.8
0.091
855e25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
154.8
56.0
40.0
0.6
16.6
70.3
54.3
‐12.6
3.4
0.092
869f25‐230
40
Weak
20
25
10%/40
7%/60
16.0
24.0
116.3
51.3
35.3
12.8
28.8
59.4
43.3
5.0
21.0
0.070
869f25‐230'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
217.7
61.2
45.2
3.2
19.2
76.5
60.4
‐11.4
4.7
0.070
855e25‐230
40
Weak
20
25
10%/40
7%/50
16.0
20.0
116.1
43.8
27.8
12.3
28.3
49.5
33.5
6.7
22.8
0.049
855e25‐230'
40
Weak
20
25
10%/40
7%/50
16.0
20.0
218.7
50.8
34.8
5.6
21.6
61.7
45.7
‐4.7
11.3
0.050
161‐69 kV
161‐55 kV
230‐69 kV
230‐55 kV
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 28
Notes:
The following notes provide information to understand the meaning of each column heading and
underlying assumptions used in the analysis. See also the one‐line diagrams in Figures 5 and 6 of
Appendix 2 for additional information.
ZL
The table provides the length of line “L” in miles to provide a high‐level, qualitative understanding of the
line impedance. The line impedance (ZL) is the length of the line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
230
954 ACSR
25.20’
0.100 + j0.786
0.000189 + J 0.00149
954 ACSR
20’ H‐frame
16’ H‐frame
161
20.16’
0.100 + j0.759
0.000384 + j 0.00293
138
795 ACSR
13’ H‐frame
16.38’
0.117 + j0.738
0.000615 + j 0.00388
115
795 ACSR
11’ H‐frame
13.86’
0.117 + j0.718
0.000886 + j 0.00543
Ztr
The transfer impedance (Ztr) represents the impedance of the system in parallel with the subsystem
under study. Analysis was performed for three levels of parallel transfer impedance which have been
characterized as strong, medium, and weak. The strong system has relatively low impedance and thus
will pick up more power flow when line “L” is tripped. The weak system has relatively high impedance
and thus will pick up less power flow when line “L” is tripped. The medium system has a mid‐range
impedance value. The actual values of the transfer impedance vary between the distribution cases and
the sub‐transmission cases.
Ztr in distribution cases (p.u.)
Ztr in sub‐transmission cases (p.u.)
Strong
0.00089 + j 0.00543
0.00354 + j 0.0217
Medium
0.00319 + j 0.0195
0.0128 + j 0.0782
Weak
0.00664 + j 0.0407
0.0266 + j 0.163
Zln1‐4
The table provides the total length of lines “ln1” through “ln4.” In all simulations these four lines have
equal length. The total length in miles provides a high‐level, qualitative understanding of the line
impedance. The line impedances are the length of each line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are the same as provided above for line “L.”
Zdist
The table provides the length of the line in miles to provide a high‐level, qualitative understanding of the
line impedance. The impedance of the distribution system or sub‐transmission system (Zdist) is the length
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 29
of the distribution tie or sub‐transmission line in miles times the per mile impedance. A value of zero
miles is used when the distribution tie is a solid bus tie. Assumptions used in determining the per mile
impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
69
636 ACSR
6’ Horizontal
7.56’
0.145 + j0.657
0.00305 + j 0.0138
55
556 ACSR
6’ Horizontal
7.56’
0.168 + j0.677
0.00555 + j 0.0224
46
477 ACSR
6’ Triangular
6.00’
0.193 + j0.647
0.00913 + j 0.0306
34.5
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0162 + j 0.0503
23
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0365 + j 0.113
12.47
336 ACSR
2’ Horizontal
2.52’
0.274 + j0.563
0.176 + j 0.362
ZT1‐4
The transformer impedance is reported as percent impedance on the transformer MVA base. Each
transformer has three ratings: OA (oil and air), FA (forced air – i.e., fans), and FOA (forced oil and air –
i.e., pumps and fans). The transformer MVA base rating is the OA rating. The FA rating is 133% of the OA
rating and the FOA rating is 167% of the OA rating (e.g., a 20 MVA transformer has a 20 MVA OA rating,
26.7 MVA FA rating, and 33.3 MVA FOA rating, typically identified as a nameplate of 20/26.7/33.3 MVA).
The transformer impedance and rating for each voltage level are based on typical values. Distribution
transformer impedance is generally higher to limit current on the distribution equipment. Secondary
current typically is not a concern on sub‐transmission transformers, so impedance is typically lower to
limit reactive power losses and voltage drop.
L1, L2, L3, L4
The transformer load is based on the transformer OA rating. Transformers are loaded at 80 percent of
the transformer base MVA in the simulations modeling a peak system load condition. The substations
modeled have two transformers, with each transformer able to supply the total station load. Thus, if one
transformer is forced out‐of‐service, the load on the remaining transformer will be 160 percent of its
base rating, which is approximately equal to its FOA rating.
Transformers are loaded at 40 percent of the transformer base MVA in the simulations modeling a light
system load condition.
HV Line "L" in‐service: PL, Pln1, , Pln2, Pln3, Pln4
The loading on each line, with all lines in service, is listed in MVA. The loading on line “L” is the power
that is redistributed between the parallel transmission system and the distribution or sub‐transmission
system when line “L” is taken out of service.
HV Line "L" out‐of‐service: Pln1, , Pln2, Pln3, Pln4
The loading on each line, with line “L” out‐of‐service, is listed in MVA.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 30
LODF
The Line Outage Distribution Factor (LODF) is the fraction of the load on line “L” that is picked up on the
distribution or sub‐transmission system. This information is included for illustrative purposes to
understand the analysis, but was not used in identifying the voltage threshold for Exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 31
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV
In the course of developing ‘real‐world’ scenarios for the analysis of potential sub‐100 kV loop flows, the
Standard Drafting Team found that the industry has employed various measures to minimize the subject
loop flows. Some of these methods that were found to be applied by entities on sub‐100 kV loop
systems are described below. However, it is important to note that the presence of the equipment in
the following examples does not remove or lessen an entity’s obligations associated with the bright‐line
application of the Bulk Electric System (BES) definition.
Sustained power flow through substation power transformers and low voltage loops is generally
undesirable and, in some instances injurious. For this reason, power system engineers typically address
this issue in their design, operating, and planning criteria and apply methods to prevent this condition
from occurring. The high impedance of transformers and low voltage elements inherently prevent
excessive flow, but in many instances this flow can exceed ratings of equipment. For these reasons
entities develop control schemes, add relaying, and provide operational and planning guidelines to
prevent this loop flow. Figure 7 depicts two systems that could provide a possible loop flow across the
low voltage system and back up to the high voltage system. The loop flow in these diagrams is increased
when the breaker on the high voltage side (breaker B) is opened.
The diagrams presented below depict a generic power system. The higher voltage and lower voltage
circuit breakers and bus arrangements will, in practice, vary (i.e., straight bus, half‐breaker, ring bus,
breaker‐and‐a‐half, etc.), but the concepts remain the same.
Specifically, Figure 7, shown below, depicts segments of an electrical power system. They consist of a
greater than 100 kV system and a sub‐100 kV system. Figure 7 depicts the power flow through the
electrical system under the condition that all circuit breakers are closed (normal condition). In the event
that circuit breaker B opens (i.e., manually, supervisory control, or protective device operation) and (1)
and either of the sub‐100 kV line circuit breakers (A or C) or (2) either of the low‐side transformer circuit
breakers (D or F) or (3) the low‐side bus tie circuit breaker (E) does not open, a condition could occur
where some amount of flow will occur through the sub‐100 kV system to the greater than 100 kV
system. This flow is severely limited by the high impedance of the two transformers in series and the
sub‐100 kV system impedance. This condition, however, may be deemed undesirable from an
equipment standpoint and precautions may be taken to prevent it. Subsequent sections of this appendix
show some of the physical schemes that entities can employ in this regard.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 32
Figure 7. Summary of Loop Flow
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 33
Interlocked Control Schemes
Interlocking control schemes can be used to prevent low voltage loop flow. One method to preclude
sustained power flow from the lower voltage to the higher voltage portion of the system is to include
control system interlocks which will cross‐trip certain circuit breaker(s) when other specified circuit
breakers are opened. This condition is generally rare since bus designs and protective relay system
operations generally do not result in this condition occurring. Operational guidelines usually instruct
personnel to avoid the use of the interlocking schemes during normal or planned switching. However,
unplanned actions can cause breakers to open and result in the desirable operation of the interlocking
schemes. This method, therefore, is considered to be conservative but, never‐the‐less, it is applied in
some instances.
Figure 8 below shows how an interlock scheme would function to prevent low voltage loop flow. When
the high side breaker (breaker B) is opened, the low side breaker (breaker E) is also opened. This action
prevents low side loop flow. The interlocking scheme could be applied in various combinations and the
figure below is a simplified illustration of such a scheme.
Figure 8. Interlocking Schemes
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 34
Reverse Power Schemes
Protection schemes can also be deployed to prevent sustained loop flows through the sub‐100 kV
system. Reverse power applications are one example of a protection scheme that prevents sustained
undesirable low voltage loop flow. In some instances, protective devices will preclude sustained loop
flows due to their settings and in other instances protective schemes are specifically applied to preclude
this undesirable operating condition.
Figure 9 below shows how a reverse power scheme would function to prevent sub‐100 kV loop flow.
When the high side breaker (breaker B) is opened, current may flow from the high voltage side (breaker
A) through the low voltage bus and back to the high voltage side (breaker C). A relay on breaker F is
applied to sense the reverse flow (relay shown in yellow in the diagram) and will operate if this flow
continues (relay shown in red in the diagram). When the reverse power relay operates it will trip
breaker F. This action prevents reverse power flow through the transformer and low voltage loop flow.
The reverse power scheme is set to sense a minimum amount of power flowing in a reverse direction
and is usually set much less than the transformer rating. The figure below is a simplified illustration of a
reverse power scheme.
Figure 9. Reverse Power Schemes
Transformer Overcurrent Limitations
Transformer overcurrent protection schemes can also be deployed to prevent sustained loop flows
through the sub‐100 kV system. Figure 10 below shows how a transformer overcurrent scheme would
function to prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current
may flow from the high voltage side (breaker A) through the low voltage bus and back to the high
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 35
voltage side (breaker C). The relay on the transformer and breaker D is applied to protect the
transformer from excessive overloads and faults on the low voltage system. If a fault occurs or the
transformer is over‐loaded then the relay on breaker D will sense this excessive flow (relay shown in
yellow in the diagram) and will operate if this flow continues (relay shown in red in the diagram). When
the transformer overcurrent relay operates it will trip breaker D. This action unloads the transformer in
question and prevents low voltage loop flow. The transformer overcurrent relay is typically set to allow
the transformer to be loaded to the emergency rating of the transformer plus a small safety margin.
The figure below is a simplified illustration of a transformer overcurrent scheme.
Figure 10. Transformer Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 36
Feeder Overcurrent Limitations
Feeder overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 11 below shows how a feeder overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage feeder, through a feeder tie, and back to the
high voltage side (breaker C). The relay on the feeder and breaker G is applied to protect the feeder
from excessive overloads and faults on the low voltage feeder. If a fault occurs or the feeder is over
loaded, the relay on breaker G will sense this excessive flow (relay shown in yellow in the diagram) and
will operate if this flow continues (relay shown in red in the diagram). When the feeder overcurrent
relay operates it will trip breaker G. This action opens the feeder breaker and prevents low voltage loop
flow. The feeder overcurrent relay is typically set to allow the feeder to be loaded to the emergency
rating of the feeder rating plus a small safety margin. The figure below is a simplified illustration of a
feeder overcurrent power scheme.
Figure 11. Feeder Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 37
Bus Tie Overcurrent Limitations
Bus tie overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 12 below shows how a bus tie overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage bus and back to the high voltage side (breaker
C). The relay on the bus tie and breaker E is applied to protect the bus from excessive overloads and
faults on the low voltage bus(ses). If a fault occurs or the bus is over loaded, then the overcurrent relay
on breaker E will sense this excessive flow (relay shown in yellow in the diagram) and will operate if this
flow continues (relay shown in red in the diagram). When the bus tie overcurrent relay operates, it will
trip breaker E. This action opens the bus tie breaker and prevents sustained low voltage loop flow. The
bus tie overcurrent relay is typically set to allow the bus to be loaded to the emergency rating plus a
small safety margin. The figure below is a simplified illustration of a bus tie overcurrent power scheme.
A
C
C
A
B
B
> 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
D
D
F
R
F
R
E
E
< 100kV
Loop Flow
Load
Load
Load
BUS TIE (Outage)
Load
Bus Tie Operate
Figure 12. Bus Tie Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 38
Custom Protection and Control Schemes
Custom protection and control schemes may also be deployed to prevent loop flows through the sub‐
100 kV system. Figure 13 below shows how such schemes would function to prevent sub‐100 kV loop
flow. When the greater than 100 kV line 1 breakers (breakers D and G) open, current may flow from the
high voltage side (breaker E) through the low voltage bus and back to the high voltage side (breaker H).
The custom scheme implemented at the substation will trip or run back generation to prevent over
loads and sustained loop flows on the low voltage system.
A
Gen 1
B
C
Line 2
F
I
D
Line 1
G
J
E
A
Gen 1
H
Gen 2
B
C
Line 2
F
I
D
Line 1
G
J
E
H
Gen 2
> 100kV
< 100kV
> 100kV
< 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
Load
Loop Flow
Load
Load
Line Outage
Load
Custom Scheme Operates to Reduce Gen
Figure 13. Custom Scheme Operations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 39
Appendix 4 Summary
The issues and methods described in Appendix 4 are reflective of why, in most instances, conditions of
sustained loop flows through sub‐100 kV systems are alleviated. When the low voltage is much less
than 100 kV, the design considerations shown above become even more pertinent and preventative
methods are employed; BES reliability is not the main concern, protecting the equipment from physical
damage is the primary concern. In the vast majority of cases, robust planning and operating criteria and
procedures will alleviate any concerns regarding sustained loop flows.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 40
Exhibit E
Summary of Development History and Record of Development of Proposed Definition
Exhibit E - Summary of the Standard Development Proceedings and Record of
Development of Proposed Definition of Bulk Electric System
The development record for the proposed revisions to the Definition of Bulk Electric System
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 F.
II.
Standard Development History
A. Standard Authorization Request Development
The Standard Authorization Request (“SAR”) for Phase 2 of Project 2010-17 Definition
of the Bulk Electric System (“BES”) was submitted on December 2, 2011 as a request for a
revision to an existing Standard. The initial draft of the Phase 2 SAR was posted from January 4,
2012, to February 3, 2012, for a 30-day public comment period. Stakeholders were asked to
provide feedback on the scope of the proposed Phase 2 project as well as specific suggestions for
existing sources of data or technical input to support revisions. A supplemental SAR for Phase 2
was submitted on January 16, 2013, and the final SAR for Phase 2 was revised on March 12,
2012 and finalized on July 10, 2012.
B. The First Posting – Formal Comment Period and Initial Ballot
The first draft of the Phase 2 Definition of BES was posted for a 45-day comment period
from May 29, 2013, to July 12, 2013, with an initial ballot held from July 3, 2013 to July 12,
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2006).
2013. Several documents were posted for guidance with the first draft, including the Unofficial
Comment Form; NERC Planning Committee Report on Analysis of Thresholds; the Drafting
Team Initial Rationale for Radial Exclusion Voltage Threshold; and the Phase 2 SAR and
supplemental SAR. The initial ballot received an 85.53% quorum, and an approval of 49.73%.
There were 93 sets of responses on the first draft, with comments from more than 225 different
people from approximately 138 companies representing all 10 of the industry segments. In
response to comments, the standard drafting team made several changes to the draft definition
including:
-
Removed “dispersed power producing resources” from Inclusion I2 and
modified several other inclusions/exclusions;
Replaced and modified Inclusion I4, which covered dispersed power
producing resources;
Modified Note 2 of Exclusion E1: Radial Systems, to increase the voltage
level from 30 kV to 50 kV
Modified the language in the “Implementation Plan and effective date
language”;
Made minor typographical modifications to Inclusion I2(a), Exclusion E3(b),
and Exclusion E4
C. The Second Posting – Formal Comment Period and Additional Ballot
The second draft of the Definition for Phase 2 was posted for a formal 30-day comment
period from August 6, 2013 to September 4, 2013, with an additional ballot held from August 26,
2013 to September 4, 2013.2 The additional ballot achieved a 78.68% quorum, and an approval
of 66.11%. The standard drafting team received 65 sets of comments from 153 different people
from approximately 117 different companies representing all 10 industry segments. Several
changes were made to the draft of the Phase 2 Definition of BES including:
2
On August 2, 2013, the NERC Standards Committee authorized a waiver of the NERC Standard Processes
Manual to permit the comment period that began on August 6, 2013 as well as any subsequent comment period prior
to a final ballot of Phase 2 of the Definition of Bulk Electric System. The waiver allows the comment periods to be
shortened from 45 days to 30, with a ballot during the last ten days of the comment period.
2
-
-
Modified the language of Inclusion I4 to clearly reflect the SDT’s intent to
include individual dispersed power producing units (such as wind and solar units)
that aggregate to greater than 75 MVA , along with the collector system that
connects these units, from the point they aggregate to greater than 75 MVA to the
point of connection at 100 kV or higher;
Modified the language in the Implementation Plan to reflect the differences in
regulatory regimes in various jurisdictions;
Corrected minor typographical errors in the white paper on the 50 kV
threshold.
D. Third Posting - Formal Comment Period and Additional Ballot
The third draft of the standard was posted with the Implementation Plan, and a number of
supporting documents including the Unofficial Comment Form, White Paper to Support sub-100
kV Threshold, the Phase 2 SAR, and the meeting minutes for the August 2, 2013, Standards
Committee meeting. The NERC Standards Committee authorized a waiver of the NERC
Standard Process Manual to shorten the next and any subsequent comment periods for Phase 2 of
Project 2010-17, prior to the final ballot from 45 days to 30 days, with a ballot conducted during
the last 10 days of the comment period.
The 30-day comment period ran from September 27, 2013 to October 28, 2013, and
included an additional ballot from October 18, 2013 to October 29, 2013. The additional ballot
achieved a 75.83% quorum, and an approval of 72. 55%. The standard drafting team received 40
sets of comments from approximately 98 different people from approximately 66 different
companies representing all 10 industry segments. The standard drafting team did not receive any
technically supported arguments to support making any changes to the posted definition or the
Implementation Plan.
E. Fourth Posting – Final Ballot
The fourth draft of the standard was posted with the Implementation Plan, and a number
of supporting documents including the White Paper to Support sub-100 kV Threshold and the
3
Phase 2 SAR. The final ballot for Phase 2 was open from November 8, 2013 to November 18,
2013. The final ballot achieved a quorum of 81.68%, and an approval of 74.34%.
4
Project 2010-17 Proposed Definition of Bulk Electric System
Related Files
Status:
The proposed Definition of Bulk Electric System was adopted by the NERC Board of Trustees on
November 21, 2013, and will be filed with the appropriate regulatory agency.
Background:
On December 20, 2012 the Federal Energy Regulatory Commission (the Commission) issued Order No.
773, approving the definition of Bulk Electric System filed as a result of Phase 1 of the Definition of Bulk
Electric System project. In Order No. 773, as clarified in Order 773-A, the Commission directed NERC to:
(1) modify the exclusions for radial systems (Exclusion E1) and local networks (Exclusion E3) so that they
do not apply to tie-lines, i.e. generator interconnection facilities, for BES generators; and (2) modify the
local network exclusion to remove the 100 kV minimum operating voltage to allow systems that include
one or more looped configurations connected below 100 kV to be eligible for the local network
exclusion.
In Order No. 773-A, the Commission noted that facilities below 100 kV can be a significant factor in a
major blackout. The Commission cited the joint NERC and Commission staff report on the September 8,
2011, Arizona-Southern California blackout in support of its decision to include all facilities that have a
material impact on the reliability of the Bulk-Power System. The Commission’s analysis of the impact of
the revisions to the definition of BES to address Order No. 773 directives reflects the intention that the
revised definition would not dramatically impact the footprint of the BES.
On May 23, 2013, NERC filed a motion with FERC, requesting that the effective date of Order 773 be
extended by one year, from July 1, 2013 to July 1, 2014. On June 6, 2013, FERC granted this request. In
its order, FERC stated that “NERC should submit a filing that includes proposed modifications to comply
with the directives pertaining to exclusions E1 and E3 as soon as possible prior to December 31, 2013.
Any delay in the submission of a filing that addresses the responsive modifications could impede the
Commission’s ability to act on the directives prior to July 1, 2014.”
Purpose/Industry Need:
On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk Electric
System so that the definition encompasses all Elements and Facilities necessary for the reliable
operation and planning of the interconnected bulk power system. Phase I of Project 2010-17 Definition
of Bulk Electric System concluded on November 21, 2011 with stakeholder approval of a revised
definition of Bulk Electric System and application form titled ‘Detailed Information to Support an
Exception Request’ referenced in the Rules of Procedure Exception Process. The revised definition,
modifications to the Rules of Procedure to provide a process for determining exceptions to the
definition, and an application form to support that process, will all be presented to the NERC Board of
Trustees for adoption and then filed with regulatory authorities for approval.
Phase 2 of the project was initiated to develop appropriate technical justification to support refinements
to the definition that were suggested by stakeholders during Phase I, and to refine the definition as
technically justified. In addition, during Phase 2 the drafting team will address FERC’s directives from
Orders 773 and 773-A.
Draft
Action
Dates
Results
Final Ballot
Info (49)
Summary (50)
Vote>>
11/08/13 11/18/13
(closed)
Additional Ballot
10/18/13 10/29/13
Consideration of
Comments
Draft 4
Clean (43)| Redline
to Last Posting (44)
| Redline to Last
Approved (45)
Implementation
Plan
Clean (46)
Supporting
Documents:
Ballot Results (51)
White Paper to
Support sub-100 kV
Threshold (47)
SAR (48)
Draft 3
Clean (28)| Redline
to Last Posting (29)
Implementation
Plan
Clean (30) |
Redline to Last
Posting (31)
Supporting
Documents:
Unofficial Comment
Form (Word) (32)
Updated Info (36) Extended an
additional day
Info (37)
to achieve
quorum.
Vote>>
Summary (39)
Ballot Results (40)
(closed)
Formal Comment
Period
Info (38)
09/27/13 10/29/13
Submit
(closed)
Comments>>
Consideration of
Comments (42)
Comments Received
(41)
White Paper to
Support sub-100 kV
Threshold (33)
SAR (34)
Standards
Committee
Authorization to
Waive the Standard
Process (35)
Draft 2
Clean (15)
Redline to Last
Posting (16)
Implementation
Plan
Formal Comment
Period
Updated Info(23)
Submit
Comments>>
08/06/13 09/04/13
(closed)
Comments
Received (24)
Clean (17)
Redline to Last
Posting (18)
Consideration of
Comments>>(27)
Supporting
Documents
White Paper to
Support sub-100 kV
Threshold (19)
SAR (20)
Unofficial Comment
Form (21)
Notice of Request
to Waive the
Standard Process
(22)
Additional Ballot
Vote>>
08/26/13 09/04/13
(closed)
Summary>>(25)
Ballot Results>>(26)
Draft 1 - Phase 2
Definition
Clean (1)| Redline
to Last Approved
(2)
Implementation
Plan (3)
Supporting
Documents
Comment Period
Info>>(9)
Unofficial Comment Submit
Comments>>
Form (Word
Version)(4)
--------------NERC Planning
Committee Report
on Analysis of
Thresholds (5)
Drafting Team
Initial Rationale for
Radial Exclusion
Voltage Threshold
(6)
Comments
--------------------- Received>>(11)
--
05/29/13 Summary>>(12)
Join Ballot Pool>> 06/27/13
(closed)
---------------------------------- Ballot Results>>(13)
Initial Ballot
--Updated Info (10)
07/03/13 07/12/13
(closed)
Vote>>
Phase 2 SAR (7)
Phase 2
Supplemental SAR
(8)
------------------For Information
Phase 1: Bulk
Electric System
Definition
Reference
Document (April
2013)
05/29/13 07/12/13
(closed)
On June 13, 2013,
FERC issued an
order extending
the effective date
of the definition
of Bulk Electric
System
developed in
Phase 1. As a
result, this
Consideration of
Comments>>(14)
reference
document is
outdated.
Revisions to the
document will be
developed at a
later date to
conform to the
definition being
developed in
Phase 2
Phase 2
For Information
SAR
Supplemental SAR
Draft 1
Guidance
Document
Informal
Comment Period
Supporting
Materials:
Info>>
Unofficial Comment
Form (Word)
Submit
Comments>>
Definition of Bulk
Electric System
(Filed with FERC
01/23/12)
Phase 2
Posted for
Information
10/4/2012 11/5/2012
(closed)
7/10/2012
Comments
Received>>
Consideration of
Comments>>
FINAL SAR
Clean | Redline
Phase 2
Draft 1 SAR
Comment Period
Supporting
Info>>
Materials:
Definition of Bulk
Submit
Electric System (last
Comments>>
approved)
1/4/2012 2/3/2012
(closed)
Comments
Received>>
Unofficial Comment
Form (Word)
Draft 3
Definition of Bulk
Electric System
Clean | Redline to
Last Posting
Implementation
Plan for Definition
Clean | Redline to
Last Posting
Recirculation
Ballots
Info>>
Summary>>
11/10/2011 11/21/2011
(closed)
BES Definition Full
Record>>
BES Exceptions Full
Record>>
Vote>>
Detailed
Information to
Support BES
Exceptions Request
Clean | Redline to
Last Posting
Draft 2
Definition of Bulk
Electric System
Initial Ballot of
Definition of BES
Updated Info>>
9/30/2011 10/10/2011
(closed)
Summary>>
Full Record>>
Consideration of
Comments>>
Clean | Redline to
Last Posting
Info>>
Vote>>
Implementation
Plan for Definition
Clean | Redline to
Last Posting
8/26/2011 Join Ballot Pool>> 9/26/2011
(closed)
Supporting
Materials
Comment Form
(Word)
Draft Supplemental
SAR
090111 Letter to A. Comment Period
Mosher from
Chairman Anderson Updated Info>>
Info>>
082411 Letter to
Chairman Anderson Submit
Comments>>
from from A.
Mosher
8/26/2011 10/10/2011
(closed)
BES Definition
Comments
Received>>
9/30/2011 10/10/2011
(closed)
Summary>>
Consideration of
Comments>>
Technical
Justification for
Local Network
Exclusion
Draft 2
Detailed
Information to
Support BES
Exceptions Request
Supporting
Materials
Initial Ballot of
Detailed
Information to
Support BES
Exceptions
Request
Info>>
Vote>>
Full Record>>
Consideration of
Comments>>
Comment Form
(Word)
8/26/2011 Join Ballot Pool>> 9/26/2011
(closed)
Comment Period
Info>>
Submit
Comments>>
Draft 1
Comment Period
Technical Principles
for Demonstrating
BES Exceptions
Submit
Comments>>
Comment Form
(Word)
SAR Version 2
Clean | Redline to
last posting
8/26/2011 10/10/2011
(closed)
BES Exceptions
Comments
Received>>
Consideration of
Comments>>
5/11/2011 6/10/2011
(closed)
Comments
Received>>
Technical
Principles
Consideration of
Comments>>
Info>>
Bulk Electric
System Definition
Revision Status
Info>>
Definition of Bulk
Electric System
Clean | Redline to
last posting
Implementation
Plan for Definition
Clean
Comment Form
(Word)
Comment Period
Info>>
Submit
Comments>>
4/28/2011 5/27/2011
(closed)
Comments
Received>>
Definition of
Bulk Electric
System
Consideration of
Comments>>
Draft SAR Version 1
Definition of Bulk
Electric System
BES SAR &
Definition
Consideration of
Comments>>
Clean | Redline to
last approval
Supporting
Materials:
Comment Period
Concept Paper
Unofficial BES SAR
& Definition
Comment Form
(Word)
Official BES
Definition
Exception Process
Comment Form
(Word)
Info>>
12/17/2010 –
1/21/2011
(closed)
Submit
Comments>>
BES Definition
Exception Process
Comments Received
Comments Received
>>
BES Definition
Exception
Process
Consideration of
Comments
Q1>>
Q2>>
Q3>>
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
Proposed Action Plan and Description of Current Draft:
This draft is the first comment posting and initial ballot for the Phase 2 revised definition of the Bulk
Electric System (BES).
Future Development Plan:
Anticipated Actions
Anticipated Delivery
1. Recirculation ballot
3Q13
2. BOT adoption
4Q13
Draft 1 – May 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition will
go into effect on the first day of the second calendar quarter after Board of Trustees adoption.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 1 – May 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) and dispersed power producing resources, including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above with:
a) Gross individual nameplate rating greater than 20 MVA, OR,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
Rationale for revising I2 to consolidate I2 and I4: Dispersed
power producing resources are small-scale power generation
technologies using a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the
traditional electric power system. Examples could include but are not
limited to solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Omitted.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2 or I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or,
Draft 1 – May 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2 or I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 30 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 30 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a three step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. Finally, examination of design
considerations that the industry deploys to prevent loop flow through
low voltage systems at the various voltage levels confirms that
protection is implemented to prevent such flows through low voltage
looped systems. A formal white paper is being prepared to support this
approach.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2 or I3 and do not have an
aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Power flows only into the LN and the LN does not transfer energy originating
outside the LN for delivery through the LN; and
Draft 1 – May 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Explanation of changes:
I1 – Made a non-material semantic change to provide greater clarity as suggested by industry comments.
I2 – (1) Split the inclusion into an ‘a’ and ‘b’ as suggested by industry to clarify that this is an ‘or’ statement. This is not
shown in redline as it is strictly a structure change and redlining this would mask the changes made for dispersed power
producing resources. (2) Added the dispersed power producing resources phrase to provide clarity as to the inclusion of
such resources herein and to continue to provide the granularity for these resources noted in FERC Orders 773 and 773-A.
(3) Added a brief rationale for the revision to I2. The text box will be removed from the final filed version of the
definition. The text box language will be placed in the appropriate section(s) of the Reference Document when that
document is revised for Phase 2.
I4 – Omitted this as a separate inclusion as it is no longer needed with the inclusion of dispersed power producing
resources in Inclusion I2. Since Inclusion I2 includes what is being referred to as generator interconnection facilities, a
separate inclusion to handle collector systems is not needed. The numbering of the inclusions has been retained so as not
to invalidate software tools developed for the Phase 1 definition.
I5 – Made a semantic addition to provide clarity as suggested by industry comments.
E1 – Added Note 2 on looped configurations, which provides a floor below which an entity does not have to consider the
loop in its determination of a radial system. Preliminary justification for the value is shown in separate supporting
documents for this posting, and a brief description of the rationale is included in a text box within E1. A formal white
paper will be developed justifying this approach. The language in the text box will be deleted from the final filed definition
and will be included in the appropriate sections of the Reference Document.
o E1 b) and c) – Changed to address directives in Orders 773 and 773-A for generator interconnection facilities.
The “…with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating)” language remains in
the definition even with the addition of Inclusion I2 as it refers to the aggregate of multiple sites along the radial.
E3 – (1) Addressed directive in Orders 773 and 773-A by deleting the ‘or above 100 kV but’ phrasing. (2) Semantic
change replacing ‘retail customer Load’ with ‘retail customers’ to provide clarity as suggested by industry comments.
o E3a) - Changed to address directives in Orders 773 and 773-A for the generator interconnection facilities.
o E3c) - Made a semantic change to provide clarity as suggested by industry comments.
E4 – Deleted ownership implications as the BES definition is a component-based definition and does not take into account
the ownership or operation of the actual equipment.
Draft 1 – May 2013
Page 5 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will
be removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
Proposed Action Plan and Description of Current Draft:
This draft is the first comment posting and initial ballot for the Phase 2 revised definition of the
Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
Anticipated Delivery
1. Recirculation ballot
3Q13
2. BOT adoption
4Q13
Draft 1 – May 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 1 – May 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will
be balloted in the same manner as a Reliability Standard. When the approved definition
becomes effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated
at 100 kV or higher unless excluded underby application of Exclusion E1 or E3.
I2 – Generating resource(s) and dispersed power producing resources, including the
generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA, OR,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
Rationale for revising I2 to consolidate I2 and I4: Dispersed
power producing resources are small-scale power generation
technologies using a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the
traditional electric power system. Examples could include but are not
limited to solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above Omitted.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1 unless excluded by application of Exclusion E4.
Exclusions:
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
Draft 1 – May 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
b) Only includes generation resources, not identified in Inclusions I2 or I3,
with an aggregate capacity less than or equal to 75 MVA (gross nameplate
rating). Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusions I2 or I3, with an aggregate capacity of nonretail generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as
depicted on prints or one-line diagrams for example, does not affect this
exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 30
kV or less, between configurations being considered as radial systems, does
not affect this exclusion.
Rationale: A threshold of 30 kV or less has been proposed for loops
between radial systems when considering the application of Exclusion
E1. The SDT used a three step approach to determine the voltage level.
As a first step, regional voltage levels that are monitored on major
interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. Finally, examination of design
considerations that the industry deploys to prevent loop flow through
low voltage systems at the various voltage levels confirms that
protection is implemented to prevent such flows through low voltage
looped systems.
E2 - A generating unit or multiple generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customers Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
Draft 1 – May 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusions I2 or I3 and do
not have an aggregate capacity of non-retail generation greater than 75
MVA (gross nameplate rating);
b) Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any
monitored Facility of apart of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated byinstalled for the sole benefit of thea
retail customersolely for its own use.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.
Explanation of changes:
I1 – Made a non-material semantic change to provide greater clarity as suggested by industry comments.
I2 – (1) Split the inclusion into an ‘a’ and ‘b’ as suggested by industry to clarify that this is an ‘or’ statement. This is not
shown in redline as it is strictly a structure change and redlining this would mask the changes made for dispersed power
producing resources. (2) Added the dispersed power producing resources phrase to provide clarity as to the inclusion of such
resources herein and to continue to provide the granularity for these resources noted in FERC Orders 773 and 773-A. (3)
Added a brief rationale for the revision to I2. The text box will be removed from the final filed version of the definition. The
text box language will be placed in the appropriate section(s) of the Reference Document when that document is revised for
Phase 2.
I4 – Omitted this as a separate inclusion as it is no longer needed with the inclusion of dispersed power producing resources in
Inclusion I2. Since Inclusion I2 includes what is being referred to as generator interconnection facilities, a separate inclusion
to handle collector systems is not needed. The numbering of the inclusions has been retained so as not to invalidate software
tools developed for the Phase 1 definition.
I5 – Made a semantic addition to provide clarity as suggested by industry comments.
E1 – Added Note 2 on looped configurations, which provides a floor below which an entity does not have to consider the loop
in its determination of a radial system. Preliminary justification for the value is shown in separate supporting documents for
this posting, and a brief description of the rationale is included in a text box within E1. A formal white paper will be
developed justifying this approach. The language in the text box will be deleted from the final filed definition and will be
included in the appropriate sections of the Reference Document.
o E1 b) and c) – Changed to address directives in Orders 773 and 773-A for generator interconnection facilities. The
“…with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating)” language remains in the
definition even with the addition of Inclusion I2 as it refers to the aggregate of multiple sites along the radial.
E3 – (1) Addressed directive in Orders 773 and 773-A by deleting the ‘or above 100 kV but’ phrasing. (2) Semantic
change replacing ‘retail customer Load’ with ‘retail customers’ to provide clarity as suggested by industry comments.
o E3a) - Changed to address directives in Orders 773 and 773-A for the generator
E4 - Deleted ownership implications as the BES definition is a component-based definition and does not take into account the
ownership or operation of the actual equipment.
Draft 1 – May 2013
Page 5 of 5
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall
go into effect on the first day of the second calendar quarter after Board of Trustees adoption.
Compliance obligations for the Phase 2 definition would begin:
Twenty-four months after the applicable effective date of the definition (for newly identified
Elements), or
If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case-by-case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Unofficial Comment Form
Project 2010-17 Definition of Bulk Electric System
Phase 2 | First Draft
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the first draft of the Definition of the Bulk Electric System (Project 2010‐17 – Phase 2). The
electronic comment form must be completed by 8 p.m. ET, July 12, 2013.
If you have questions please contact Ed Dobrowolski at [email protected] or by telephone at 609‐
947‐3673.
Background Information
The SDT has been working on addressing the issues presented in the Standard Authorization Requests for
Project 2010‐17 Definition of the BES – Phase 2. The output of this work is shown in the first posting of
the Phase 2 roadmap document.
In Phase 1, industry asked several questions regarding the technical justification of the threshold values
shown in the definition. Due to the FERC mandated scheduled for work on Phase 1, analysis of the
various thresholds was delayed until Phase 2. At the direction of the NERC Board of Trustees, the NERC
Planning Committee was tasked with analysis of threshold values as part of Phase 2 of the project. The
NERC Planning Committee responded in its report entitled “Review of Bulk Electric System Definition
Thresholds” dated March 2013, which has been posted on the Project 2010‐17 webpage as part of the
background material for this posting. The NERC Planning Committee report recommended that the
following thresholds be maintained:
100 kV bright‐line
20/75 MVA generation
No minimum value for reactive devices
The report did suggest possible changes to the local network exclusion regarding power flow and voltage
levels. However, the SDT believes that such changes are contrary to the philosophy of local networks,
would necessitate additional analysis workload, and would turn the evaluation from an operating
timeframe to a planning environment. Therefore, the SDT is maintaining the status quo for the local
network exclusion in Phase 2 with regard to threshold values and power flow issues.
FERC issued Order No. 773‐A on April 18, 2013. In that order, FERC affirmed Order 773 and directed NERC
to eliminate the 100 kV minimum in the local network exclusion, and to also make certain that generation
interconnection facilities that are used to interconnect BES generation with BES transmission elements
are determined to be BES elements.
The SDT has posed two questions in this posting addressing how it responded to those directives.
Question 1 below deals with the removal of the 100 kV minimum from the local network exclusion:
“E3 ‐ Local networks (LN): A group of contiguous transmission Elements operated at or above 100 kV
but less than 300 kV that distribute power to Load rather than transfer bulk power across the
interconnected system. LN’s emanate from multiple points of connection at 100 kV or higher to
improve the level of service to retail customers Load and not to accommodate bulk power transfer
across the interconnected system.”
Question 2 below deals with the proposed solution for generation interconnection facilities in the local
network and radial system exclusions:
“E3a ‐ Limits on connected generation: The LN and its underlying Elements do not include generation
resources identified in Inclusions I2 or I3 and do not have an aggregate capacity of non‐retail
generation greater than 75 MVA (gross nameplate rating);” and
“E1b ‐ Only includes generation resources, not identified in Inclusions I2 or I3, with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating).” And
“E1c ‐ Where the radial system serves Load and includes generation resources, not identified in
Inclusions I2 or I3, with an aggregate capacity of non‐retail generation less than or equal to 75 MVA
(gross nameplate rating).”
The SDT is proposing an equal and effective alternative to the issue of sub‐100 kV loop analysis with
respect to Exclusion E1. A threshold of 30 kV or less has been proposed for loops between radial systems
when considering the application of Exclusion E1. The SDT used a three‐step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored on major interfaces, paths, and
monitored elements to ensure the reliable operation of the interconnected transmission system were
examined to determine the lowest monitored voltage level. Next, power system analyses determined the
maximum amount of power that can be transferred through the low voltage systems, when looped, under
a worst case scenario at various voltage levels. Finally, examination of design considerations that the
industry deploys to prevent loop flow through low voltage systems at the various voltage levels confirms
that protection is implemented to prevent such flows through low voltage looped systems. Question 3
addresses this proposal.
Unofficial Comment Form
Project 2010‐17 DBES – Phase 2 | First Draft
2
Note 2 – The presence of a contiguous loop, operated at a voltage level of 30 kV or less, between
configurations being considered as radial systems, does not affect this exclusion.
Question 4 deals with clarification on the topic of dispersed power resources as requested by industry in
Phase 1. Based on Orders 773 and 773‐A, the SDT has revised Inclusions I2 and I4 to address concerns
raised by the Commission and to establish consistency in the treatment of BES generation resources:
“I2 ‐ Generating resource(s) and dispersed power producing resources, including the generator
terminals through the high‐side of the step‐up transformer(s) connected at a voltage of 100 kV or
above with:”
Dispersed power producing resources are small-scale power generation
technologies utilizing a system designed primarily for aggregating capacity
providing an alternative to, or an enhancement of, the traditional electric
power system. Examples could include but are not limited to solar,
geothermal, energy storage, flywheels, wind, micro-turbines, and fuel cells.
and,
I4 ‐ Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity, connected
at a common point at a voltage of 100 kV or above. Omitted.
Question 5 deals with all of the language clarifications made in response to industry comments which are
listed here:
I1 – Semantic change from ‘under Exclusion E1 or E3’ to ‘by application of Exclusion E1 or E3’ to
provide greater clarity as suggested by industry comments.
I2 – Splitting the inclusion into an ‘a’ and ‘b’ as suggested by industry to provide clarity.
I5 – Semantic addition to provide clarity as suggested by industry comments.
E3 –Semantic change replacing ‘retail customer Load’ with ‘retail customers’ to provide clarity as
suggested by industry comments.
E3c) ‐ Semantic change replacing ‘a monitored Facility of’ with ‘any part of a’ to provide clarity as
suggested by industry comments.
E4 ‐ Semantic change to provide clarity as suggested by industry.
Question 6 is a generic question added to this list to accommodate any other industry concerns with the
proposed Phase 2 definition.
Unofficial Comment Form
Project 2010‐17 DBES – Phase 2 | First Draft
3
Questions
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
The SDT has asked one specific question for each specific aspect of the definition.
1. The SDT has deleted the phrase “… or above 100 kV but…” from the local network exclusion
language (E3) in response to a FERC directive. Do you agree that the SDT has correctly addressed
this directive? If you do not agree that this change 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:
2. As identified in the FERC directive, the SDT has revised the local network (Exclusion E3) and radial
system (Exclusion E1) exclusions so that they do not allow for the utilization of these exclusions for
generation interconnection facilities that are used to interconnect BES generation identified in the
generation inclusion (Inclusion I2) with BES transmission elements. Do you agree that the SDT has
correctly addressed this directive? If you do not agree that this change 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. The SDT has proposed an equally effective and efficient alternative to the Commission’s sub‐100
kV loop concerns for radial systems by the addition of Note 2 in Exclusion E1. Do you agree with
this approach? If you do not support this approach or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions and rationale
in your comments.
Yes
No
Comments:
Unofficial Comment Form
Project 2010‐17 DBES – Phase 2 | First Draft
4
4. The SDT has revised the generation resources and dispersed power resources inclusions
(Inclusions I2 and I4) in response to industry comments and Commission concerns. Do you agree
with these changes? If you do not support these changes 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. The SDT has made a number of clarifying changes to language in response to industry comments
as follows: (a) I1: Change ‘under’ to ‘by application of’; (b) I2: Split out the inclusion to clearly show
that it is an ‘or’ condition; (c) I5: Add ‘unless excluded by application of Exclusion E4’; (d) E3:
Change ‘… retail customer Load…’ to ‘retail customers’; (f) E3c: Change ‘… a monitored Facility of a
…’ to ‘… any part of a…’; (g) E4: Add the phrase ‘installed for the sole benefit of’. Do you agree
with these changes? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions (using the
letter of the change) in your comments.
Yes
No
Comments:
6. Are there any other concerns with this definition that haven’t been covered in previous questions
and comments?
Yes
No
Comments:
Unofficial Comment Form
Project 2010‐17 DBES – Phase 2 | First Draft
5
Review of Bulk
Electric System
Definition Thresholds
March 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC | Review of Bulk Electric System Definition Thresholds | January 2013
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Preface and NERC Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory authority established to evaluate
reliability of the bulk power system in North America. NERC develops and enforces reliability standards; assesses reliability
annually via a 10‐year assessment and winter and summer seasonal assessments; monitors the bulk power system; and
educates, trains, and certifies industry personnel. NERC is the Electric Reliability Organization for North America, subject to
oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1
FRCC
Florida Reliability Coordinating Council
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RFC
ReliabilityFirst Corporation
SERC
SERC Reliability Corporation
SPP RE
TRE
WECC
Southwest Power Pool Regional Entity
Texas Reliability Entity
Western Electricity Coordinating Council
NERC assesses and reports on the reliability and adequacy of the North American bulk power system, which is divided into
several assessment areas within the eight Regional Entity boundaries, as shown in the map and corresponding table above.
The users, owners, and operators of the bulk power system within these areas account for virtually all the electricity
supplied in the United States, Canada, and a portion of Baja California Norte, Mexico.
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability
Standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory
and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New
Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and
enforceable in British Columbia, Ontario, New Brunswick, and Nova Scotia. NERC has an agreement with Manitoba Hydro making
reliability standards mandatory for that entity, and Manitoba has adopted legislation setting out a framework for standards to become
mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability
organization” under Alberta’s Transportation Regulation, and certain reliability standards have been approved in that jurisdiction;
others are pending. NERC and NPCC have been recognized as standards‐setting bodies by the Régie de l’énergie of Québec, and Québec
has the framework in place for reliability standards to become mandatory and enforceable in that jurisdiction.
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Table of Contents
PREFACE AND NERC MISSION .......................................................................................................................................... 2
EXECUTIVE SUMMARY ..................................................................................................................................................... 4
1. INTRODUCTION ........................................................................................................................................................... 5
1.1 PROBLEM STATEMENT ............................................................................................................................................................. 5
1.2 PLANNING COMMITTEE ASSIGNMENTS ........................................................................................................................................ 6
1.3 CONSIDERATIONS FOR TECHNICAL JUSTIFICATION .......................................................................................................................... 6
2. TECHNICAL JUSTIFICATION FOR THE 100 KV BRIGHT LINE ............................................................................................. 7
2.1 ALTERNATIVES TO THE 100 KV BRIGHT LINE ................................................................................................................................. 7
2.2 CONCLUSIONS AND RECOMMENDATION .................................................................................................................................... 12
3. TECHNICAL JUSTIFICATION FOR GENERATOR THRESHOLDS ......................................................................................... 13
3.1. CAPACITY BREAKDOWN ......................................................................................................................................................... 13
3.2 ALTERNATIVES TO THE 20/75 MVA THRESHOLD ........................................................................................................................ 15
3.3 RECOMMENDATION FOR GENERATOR THRESHOLDS ..................................................................................................................... 17
4. TECHNICAL JUSTIFICATION FOR REACTIVE DEVICE THRESHOLD ................................................................................... 19
4.1 BACKGROUND ...................................................................................................................................................................... 19
4.2 ALTERNATIVES TO THE ZERO‐MVAR THRESHOLD UNDER CONSIDERATION ........................................................................................ 19
4.3 CONCLUSION AND RECOMMENDATION ...................................................................................................................................... 20
5. TECHNICAL JUSTIFICATION FOR POWER FLOW OUT OF LOCAL NETWORKS ................................................................. 22
5.1 BACKGROUND ...................................................................................................................................................................... 22
5.2 ALTERNATIVES TO THE ZERO POWER FLOW LIMITATION UNDER CONSIDERATION ............................................................................... 23
5.3 CONCLUSION AND RECOMMENDATION ...................................................................................................................................... 25
5.4 FURTHER CONSIDERATIONS FOR LIMITS ON THE SIZE OF LOCAL NETWORKS ...................................................................................... 25
6. RECOMMENDATIONS ................................................................................................................................................. 27
APPENDIX 1A: REQUEST FROM THE BES SDT TO THE PC ................................................................................................. 28
APPENDIX 1B: AUTHORIZATION AND PROBLEM STATEMENT FROM THE BES DEFINITION SDT (NERC STANDARDS PROJECT
2010‐17, PHASE II) ......................................................................................................................................................... 30
APPENDIX 1C: BES SDT RESPONSE TO PC REPORT (DRAFT 2012 BES DEFINITION REPORT) ............................................... 32
APPENDIX 2: INTERCONNECTION STUDY GUIDELINES ..................................................................................................... 33
APPENDIX 3: OPERATIONAL CONSIDERATIONS TO SUPPORT LOAD LIMIT ON LOCAL NETWORKS .................................... 38
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Executive Summary
In March 2012, the Definition of BES Standard Drafting Team (DBES SDT) asked the Planning Committee (PC) to review
some of the thresholds in the Bulk Electric System (BES) definition that the DBES SDT identified within the Phase I BES work
and to supply technical justifications for the following thresholds:
1.
100 kV bright‐line transmission threshold (in the core definition)
2.
Generation threshold MVA values associated with single‐unit and multiple‐unit facilities (in Inclusions I2 and I4)
3.
Reactive power threshold (MVA level) (in Inclusion I5)
4. Power flow allowed out of Local Networks (LN) (in Exclusion E3)
After analysis and review, the PC offers the following recommendations to the DBES SDT for consideration:
5.
Maintain the 100 kV bright line (core definition).
6.
Maintain Inclusions I2 and I4 as currently defined.
7.
Maintain Inclusion I5 as currently defined.
8.
Use Technical Alternative C, which proposes clarifying changes to the existing Exclusion E3 item (b) as given below
in bold:
a.
9.
Real power flows only in the LN from every point of connection to the BES for the system as planned
with all‐lines in service and also for first contingency conditions as per TPL‐001‐2, Steady State &
Stability Performance Planning Events P0, P1, and P2, and the LN does not transfer energy originating
outside the LN for delivery through the LN to the BES
Establish a size limit in the LN definition to prevent the exclusion of large networks that may have a significant
impact on reliable BES operation. This recommendation is explained in detail in the following section as well as in
Appendix 3.
The NERC PC discussed and approved the recommendations in this report and its transmittal to the DBES SDT at its
December 2012 meeting. Following the meeting, the PC Executive Committee made further changes based on the
discussion by the PC, and the final report was approved by the PC by an email ballot.
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1. Introduction
1. Introduction
In FERC Order No. 693, the Commission explained that section 215(a) of the Federal Power Act (FPA ) broadly defines the
bulk power system as:
Facilities and control systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof) [and] electric energy from generating facilities needed to maintain transmission system reliability.
The Commission also initially approved NERC’s definition of Bulk Electric System, which is an integral part of the NERC
Reliability Standards and is included in the NERC Glossary of Terms Used in Reliability Standards2, as the following:
As defined by the Regional Reliability Organization, the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or
higher. Radial transmission facilities serving only load with one transmission source are generally not included in this
definition.
In response to the Commission’s directive in Order No. 743 that NERC develop a revised definition of Bulk Electric System
using NERC’s Reliability Standards development process, NERC began work in 2011 to eliminate the Regional and
subjectivity contained within the definition. In early 2012, the NERC Board of Trustees approved a revised BES definition
and subsequently filed it with FERC under docket RM12‐6 and RM12‐7. This concluded the Phase I work associated with
developing a revised definition.
In its filing, NERC proposed the following core definition of Bulk Electric System:
Unless modified by the [inclusion and exclusion] lists shown below, all Transmission Elements operated at 100 kV or
higher and Real Power and Reactive Power resources connected at 100 kV or higher. This does not include facilities used
in the local distribution of electric energy.
As stated in the NERC filing, the revised definition of Bulk Electric System:
removes the basis for regional discretion in the current Bulk Electric System definition;
establishes a bright‐line threshold so that the Bulk Electric System is facilities that operate at 100 kV or higher, if
they are Transmission Elements, or connected at 100 kV or higher, if they are real power or reactive power
resources; and
contains specific Inclusions (I1‐I5) and Exclusions (E1‐E4).
During the initial revision of the definition of the Bulk Electric System in Phase I of Project 2010‐17, industry stakeholders
expressed concerns related to the lack of technical justification associated with the existing thresholds in the definition. Due
to time constraints in the Phase I schedule, Phase II of the project was initiated to address the lack of technical justification.
As part of this initiative, the DBES SDT asked the PC for assistance in developing technical justification for the thresholds in
the revised definition.
1.1 Problem Statement
Properly identified BES Elements are important to the reliability of the interconnected bulk power system. The ability to
properly identify BES Elements is dependent on a BES definition that is based on factors directly associated with reliability.
The revised BES definition approved by the NERC Board of Trustees and filed with FERC contains historical thresholds from
the current BES definition found in the NERC Glossary of Terms and the NERC Statement of Compliance Registry Criteria.3
These historical thresholds are not currently supported by documented technical justifications.
2
http://www.nerc.com/files/Glossary_of_Terms.pdf
On December 20, 2012, FERC issued a Final Rule on Revisions to Electric Reliability Organization Definition of Bulk Electric System and
Rules of Procedure: http://www.ferc.gov/whats‐new/comm‐meet/2012/122012/E‐5.pdf
3
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1. Introduction
The DBES SDT requested support from the NERC PC (see Appendix 1A and 1B for request authorization) and Operating
Committee (OC) to develop technical justifications to assist the SDT in considering revisions to the following thresholds that
are part of the current NERC Board of Trustees‐approved definition of the BES:
1.
100 kV bright‐line transmission threshold (in the core definition)
2.
Generation threshold MVA values associated with single‐unit and multiple‐unit facilities (in Inclusions I2 and I4)
3.
Reactive power threshold (MVA level) (in Inclusion I5)
4.
Power flow allowed out of Local Networks (LN) (in Exclusion E3)
1.2 Planning Committee Assignments
To complete this request in a timely manner, the PC assigned the development of technical justifications for the thresholds
listed above to designated subcommittees of the PC as outlined below:
Technical Justification
Assigned To:
100 kV bright‐line transmission threshold
Planning Committee Executive Committee
Generation threshold
Reliability Assessment Subcommittee
Reactive power threshold
System Analysis and Modeling Subcommittee
Power flow allowed out of local networks
System Analysis and Modeling Subcommittee
1.3 Considerations for Technical Justification
The PC, in conjunction with its technical subcommittees, noted that using power flow or dynamic studies may not lead to
definitive results and are highly dependent on varying assumptions used in the models, such as generation dispatch, load
level, system conditions, etc. Also, other aspects of reliability, such as resource adequacy, reserve margins, voltage support,
etc. need to be considered along with performing power flow and dynamic analyses. Therefore, the PC recommended that
these studies not be performed at this time in determining technical justification for the above thresholds.
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2. Technical Justification for the 100 kV Bright Line
2. Technical Justification for the 100 kV Bright Line
NERC’s filing to FERC under docket RM12‐6‐000 proposed to establish a bright‐line transmission threshold so that the “bulk
electric system” would include facilities operated at 100 kV or higher if they are Transmission Elements, or connected at
100 kV or higher if they are real‐power or reactive‐power resources. The DBES SDT asked the PC to provide technical
justification for the 100 kV threshold included in the core BES definition or propose a better alternative, if justified (see
Appendix 1).
2.1 Alternatives to the 100 kV Bright Line
Several alternatives to the 100 kV bright‐line transmission threshold were considered. The alternatives outlined below were
selected for further research and consideration.
2.1.1 Technical Alternative A – Surge Impedance Loading (SIL)
Description: Incorporate transmission lines that have a Surge Impedance Loading (SIL) above a specific criteria value (for
example, 100 MVA) and for all substations connected to a line that meets this criteria.
Technical Discussion: A key component to the reliability of the power system is the ability to continue to provide service to
load not only from nearby generating sources, but also from external sources. This has been the basis for justifying the
addition of a number of Extra High Voltage (EHV) transmission facilities throughout North America. To assess the ability of a
transmission line to carry load, or the amount of load a transmission line can effectively carry, engineers calculate its Surge
Impedance Loading.
SIL is a loading level at which the transmission line attains self‐sufficiency in reactive power (i.e., no net reactive power into
or out of the line), and is a convenient “yardstick” for measuring relative loadability (or ability of the line to carry load) of
long transmission lines operating at different nominal voltages.
For example, considering the SIL alternative, on a per‐unit basis, for uncompensated overhead transmission lines, three 500
kV circuits, six 345 kV circuits, or thirty‐four 161 kV4 circuits would be required to achieve the same loadability of a single
765 kV line. Specifically, a 765 kV line can reliably transmit 2,200–2,400 MW (i.e., 1.0 SIL) for distances up to 300 miles,
whereas the similarly situated 500 kV and 345 kV lines with bundled conductors can only deliver about 900 MW and 400
MW, respectively, over the same distance.
For short distances, these previous relationships can produce slightly different results, which reflects the thermal capacity
of transmission line. The thermal capacity of a transmission line is determined by the number or size of line conductors and
terminal equipment ratings. However, SILs for typical compensated overhead lines are two to three times those of
uncompensated overhead lines. For underground lines where air is not the insulating dielectric, SILs are three to twelve
times that of uncompensated overhead lines, with multipliers increasing as line voltages decrease.
The relative loadability of the same overhead 765 kV, 500 kV, and 345 kV lines also can be viewed in terms of transmission
“reachover,” for which a certain amount of power can be transmitted. In the first example, 1,500 MW sent over a 765 kV
line would represent a loading of approximately 0.62 SIL, which, according to the loadability characteristic of the
transmission line, could be transported reliably over a distance of up to 550 miles.
By contrast, a 345 kV line carrying the same 1,500 MW would operate at 3.8 SIL—this power would be transportable up to
approximately 50 miles (assuming adequate thermal capacity). This distance would increase to about 110 miles for a
double‐circuit 345 kV line.
The generalized line loadability characteristic incorporates the assumptions of a well‐developed system at each terminal of
the line and operating criteria designed to promote system reliability.5
4
5
Thirty four 161 kV added to original calculations
Source is American Electric Power System Facts (no endorsement; used posted transmission information)
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2. Technical Justification for the 100 kV Bright Line
SIL is a long‐accepted indicator of system loadability and capability and is at least one indicator of the reliability of a
transmission line. System studies would need to be performed to support a given bright line threshold, such as the 100
MVA mark, with delayed clearing fault simulations occurring while at the same time monitoring for cascading events,
extreme frequency excursions, and uncontrolled separation (among other events).
However, calculations from a sample power flow model’s branch data indicate that additional stress and stability studies
would need to be performed for all interconnections. Follow‐up correlation analysis would be necessary to determine
whether correlation to SIL exceeds correlation to a voltage level, and to identify the appropriate bright‐line SIL threshold for
the BES.
A transmission line’s SIL is easy to calculate, but the values obtained correspond to a voltage level, which does not provide a
better, technically justified alternative to using the 100 kV voltage level. (SIL is proportionate to the square of voltage). SIL
would simply be a surrogate to using a bright‐line voltage criteria. In addition, transmission lines would still carry portions of
power transfers, even though they may be below a certain SIL value, as the SIL value is only an indication of reactive power
equilibrium for that line. Virtually all transmission lines above 200 kV would be captured by this criterion for the SIL level.
Transmission lines below 200 kV would most likely be included in the BES if the line has series compensation or is built
underground, which increases the SIL for those types of lines.
Given that SIL would only be a surrogate for the voltage level of a transmission line, the PC recommends not selecting this
method for determining the bright‐line threshold in the BES definition.
2.1.2 Technical Alternative B – Short Circuit Values
Description: Incorporate facilities with a short circuit value greater than a specified threshold (e.g., 5,000 MVA).
Technical Discussion: Technical Alternative B to the 100 kV bright‐line transmission threshold in the BES definition would be
to perform a calculation that reflects the strength of the network at any given location or node (such as a substation bus)
using the Short Circuit MVA method. Using this approach, facilities with many sources (either transmission lines or
generation sources) would fall under the definition of the BES, given the level of short circuit MVA.
The classical approach and the method defined by ANSI/IEEE are two such industry‐accepted methods for calculating short
circuits. Both methods assume that the fault impedance is zero (bolted short circuit) and the pre‐fault voltage is constant
during the evolution of the fault. In actuality, the fault has its own impedance, and the voltage drop, due to the short‐circuit
current, lowers the driving voltage.6
The classical approach is used to calculate the system Thévenin equivalent impedance behind the fault and then to
calculate the Short Circuit MVA at the point of the fault. The ANSI/IEEE method for short circuit MVA calculation, which is
described in IEEE Std. C37.010‐19797 and its revision in 1999, is used for high‐voltage (above 1000 V) equipment.
In order to include all higher voltage facilities that may be carrying power over longer distances, a bright‐line voltage level
would also need to be included when using this method. This value could be based on operating and design specifications
of the interconnection.
Technical Alternative B is easy to calculate and is completed regularly by industry stakeholders. Calculated Short‐Circuit
MVA values are normally calculated at substation buses and display the projected fault current at each bus.
However, to use Technical Alternative B as a bright‐line criterion in the BES definition, there must also be additional criteria
developed to address the inclusion of the associated transmission lines, including transformers connected to those
substations (which may include sub‐100 kV facilities). Additionally, an MVA threshold value itself would be arbitrary and,
therefore, short circuit calculated values would vary, depending on study models, which generators are online, etc. Using
this method to identify BES facilities would result in frequent changes and thus be not practical to implement. The PC does
6
7
http://ecmweb.com/content/short‐circuit‐calculation‐methods
http://standards.ieee.org/
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2. Technical Justification for the 100 kV Bright Line
not recommend the use of the Short‐Circuit MVA method as a replacement for the bright‐line transmission threshold
identified in the current BES definition.
2.1.3 Technical Alternative C – Substation MVA Rating
Technical Discussion: Include substations with two or more lines connected to a substation with a total rated MVA greater
than a specified threshold (e.g., 800 MVA or greater) and any transmission lines with MVA ratings greater than a specified
value (e.g., 400 MVA or greater). The total substation MVA value would be the sum of all of the MVA values (or ratings) of
the transmission lines connected to a substation and may include sub‐100 kV facilities within the substation.
Technical Discussion: Technical Alternative C uses the total connected MVA rating of all lines into substations, regardless of
voltage level. The computed MVA would not include transformation within the substation, nor would it include generation
or load connected to the substation. This method would only include circuits connected to a substation in the
determination of the connected MVA value. The connected MVA method would use networked transmission lines, as used
in the current BES definition, and would also include lines that connect to the substation via the transmission system. At the
same time, it would exclude the following types of transmission lines: radial transmission lines, transmission lines to lower
voltage facilities with no transmission sources, loads, and lines connected directly to generation sources. This alternative
does not consider the power flow on the lines, but rather their MVA ratings.
Transmission line MVA calculations would then be based on the most restrictive continuous rating of the transmission
facility. Continuous ratings would be used since the BES is planned to serve peak load without relying on short‐term
overload capability. No stability ratings would be used.
Possible advantages of using the total substation‐connected MVA alternative over the 100 kV voltage threshold are that the
MVA‐based determination captures substations with multiple circuits connected to it. (Individual lines are not as important,
given the criteria to operate the system at N‐1 levels).
This method also determines the capacity of lower voltage facilities (such as transmission lines operated at voltages less
than 100 kV) that are normally closed circuits in lower voltage networks and that contribute reliability benefits to the bulk
power system. The connected MVA method may alleviate concerns that facilities operating at voltages less than 100 kV are
not considered BES facilities unless they are determined to contribute to the reliability of the local network or
interconnection. The connected MVA method also is more efficient to administer, as it reduces the number of inclusions
and exclusions necessary to separate BES facilities that contribute to the reliability of network from those that do not (also
referred to as non‐BES facilities).
However, the disadvantages of applying the connected MVA method may include challenges to address all possible
scenarios (e.g., whether generation facilities with multiple fuel types should be included or excluded). The connected MVA
method would require revision to the BES if transmission lines or equipment were uprated.
The connected MVA method could create inconsistent classification of Elements that serve similar purposes (e.g., a
transmission line between two major substations would be included; however, if two intervening step‐down stations were
constructed, the section between the two step‐down stations may be excluded even though its function as a transmission
path is not changed).
Figure 1 below shows example one‐line diagrams of three substations and the summation of MVA of lines interconnecting
the substations back to the interconnected system. The MVA interconnection of substations A and B is less than 800 MVA
and would not be included in the BES. However, substation C, with an interconnection MVA of 2,451 MVA, would be
included.
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2. Technical Justification for the 100 kV Bright Line
Figure 1: Connected MVA Calculations for Substations A, B, and C
Because MVA values are essentially arbitrary and reconfiguration could exclude assets with BPS functionality, the PC does
not recommend the use of the connected MVA of substation method as a replacement for the bright‐line transmission
threshold identified in the current BES definition.
2.1.4 Technical Alternative D – Transfer Distribution Factors
Description: Use transfer distribution factors, such as Power Transfer Distribution Factors (PTDFs)8 and Outage Transfer
Distribution Factors (ODTFs),9 to determine a bright‐line threshold for inclusion of lines and transformers in the BES.
Calculated values above a specified percentage (e.g., 3%) would determine which facilities would be considered BES.
8
Linear methods use PTDF to express the percentage of a power transfer or transaction that flows on a transmission path. PTDF is
defined as the coefficient of the linear relationship between the amount of a transaction and the flow on a line or transformer, and the
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2. Technical Justification for the 100 kV Bright Line
Technical Discussion: Technical Alternative D would use transfer distribution factors as a bright‐line threshold for inclusion
of lines and transformers in the BES. Calculated values above a specified percentage (e.g., 1%, 3%, or 5%) would determine
which facilities are classified as BES facilities and which facilities are not. The selection of this method to identify bulk
system assets has several disadvantages. First, it would require detailed power flow analyses be performed to make the
determination, and that method would need to be reviewed periodically (possibly biennially) to account for system changes
that would affect the OTDF and PTDF values. Also, it would require a review if lines or equipment were uprated. OTDF
values are dynamic and may result in frequent changes to which facilities are classified as BES.
The PC does not recommend the use of transfer distribution factors as a replacement for the bright‐line transmission
threshold identified in the current BES definition.
2.1.5 Technical Alternative E – Angular Difference
Description: Determine facilities within the BES by calculating the angular differences between substation buses. The values
used in this alternative would be determined by power flow analyses or real‐time synchrophasor data gathered from
operating phasor measurement units (PMUs).
Technical Discussion: Technical Alternative E suggests using angular differences between substation buses to determine
BES and non‐BES facilities. This method could use data from power flow analyses or real‐time synchrophasor data gathered
from phasor measurement units (PMU).10
The voltage phasor angle difference between two ends of a transmission line becomes large when the power flow on the
line is large or the line impedance is large. Similar relationships are expected to apply to the angle difference between two
buses in different areas of a power system.
A large angular difference indicates, in a general sense, a stressed power system with large power flow or increased
impedance between the areas. Simulations of the grid before the August 2003 Northeast Blackout showed increasing angle
differences between Cleveland and western Michigan, which suggests that large angle differences could be a precursor to a
system blackout.
A recent simulation study11 of potential phasor measurements on the 39‐bus New England test system shows that, of
several phasor measurements, angle differences were the best in discriminating alert limits and emergency conditions.
The increasing deployment of wide‐area measurement of phasor angles spurs interest in finding ways to use phasor angles
to determine system stress. Picking one bus in each of two areas and monitoring the phasor angle difference has an
inherent problem in that, although the angle difference is generally expected to increase with system stress, many factors
contribute to angle difference, including which two buses are chosen and the local power flows within each area. It is then
harder to give a specific meaning to the angular difference and specify threshold values that indicate when the angular
difference becomes dangerously large.
Angle differences are inherently dynamic and change with generation, load, and transmission conditions instantaneously.
The PC could not determine how this method could be used to identify BES facilities. The PC does not recommend the use
of angular difference as a replacement for the bright‐line transmission threshold identified in the current BES definition.
incremental percentage of a power transfer flowing through a facility or set of facilities for a particular transfer when there are no
contingencies.
9
OTDF is the percentage of a power transfer that flows through a monitored facility for a particular transfer when the contingent facility
is taken out of service.
10
I. Dobson, M. Parashar, C. Carter, Combining Phasor Measurements to Monitor Cutset Angles, 43rd Hawaii International Conference on
System Sciences, January 2010, Kauai, Hawaii. 2010 IEEE.
11
V. Venkatasubramanian, Y. X. Yue, G. Liu, M. Sherwood, Q. Zhang, Wide‐area monitoring and control algorithms for large power
systems using synchrophasors, IEEE Power Systems Conference and Exposition, Seattle WA, March 2009.
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2. Technical Justification for the 100 kV Bright Line
2.2 Conclusions and Recommendation
Over the years, the industry has widely used the 100 kV threshold that appears in the current BES definition to delineate
between transmission and subtransmission facilities in some areas of North America. However, the technical justification
for using that voltage level as a bright‐line threshold has been missing from the BES definition.
Significant portions of power flow transfers from generation to load centers are carried by facilities operated at 100 kV and
above. The 100–299 kV systems support the EHV (i.e., greater than 300 kV) systems during times of normal and emergency
operations and contingencies. A significant portion of the total generation in North America is connected at voltages
between 100 kV and 299 kV. Each interconnection and its associated entities perform technical analyses (including power
flow and dynamics) of their systems along with joint regional and interregional analyses. Most technical analyses model 100
kV and above facilities, and sub‐100 kV facilities in certain cases. Contingent and monitored facilities are at the 100 kV and
above level in these analyses. See Appendix 2 for detailed statistics and values for each interconnection.
While the PC recommends keeping the 100 kV voltage threshold in the revised NERC definition of the BES, it also recognizes
and has considered the inclusion of sub‐100 kV facilities in the BES because of the findings and recommendations from the
report on the Arizona – Southern California Outages of September 8, 2011. The proposed NERC Rules of Procedure
exception process may be used to include pertinent sub‐100 kV facilities on a case‐by‐case basis.
Sub‐100 kV facilities, as shown from the interconnection discussions in Appendix 2, may be necessary for the operation of
the BES but will need to be considered in the future on a case‐by‐case basis for inclusion in the BES. Registered Entities and
Regional Entities will need to address how to make these determinations going forward.
Many and varied interconnection studies indicate that 100 kV is the proper threshold needed for BES reliability.
Additionally, none of the alternatives considered in the PC’s analysis provides a convincing technical justification for change
from the bright‐line threshold.
The PC recommends maintaining the 100 kV bright line (core definition) without enhancement or changes.
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3. Technical Justification for Generator Thresholds
3. Technical Justification for Generator Thresholds
In the Phase 1 Bulk Electric System definition filing, Inclusion I2 of the BES definition provides the following statement:
“Generating resource(s) with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA including the generator terminals through the high‐side of the step‐up
transformer(s) connected at a voltage of 100 kV or above.”
The filing also states that this inclusion mirrors the text of the NERC Registry Criteria (Appendix 5B of the NERC Rules of
Procedure) for generating resources. The Phase 1 filing notes that a “basic tenet that was followed in developing the
[revised definition] was to avoid changes to Registrations . . . if such changes are not technically required for the [revised
definition] to be complete.”
While Inclusion I2 specifies “generator terminals through the high‐side of the step‐up transformer(s) connected at a voltage
of 100 kV or above,” the NERC Registry Criteria specifies a “direct connection” to the bulk power system.
Also in the Phase 1 Bulk Electric System filing, Inclusion I4 of the BES definition provides the following statement:
“Inclusion I4 identifies as part of the bulk electric system dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above.”
NERC stated in its Phase 1 filing that the goals of Inclusion I4 were to accommodate the effects of variable generation on
the Bulk Electric System. It further states that even though Inclusion I4 could be considered subsumed in Inclusion I2
(generating resources), NERC believes it is appropriate “to expressly cover dispersed power producing resources utilizing a
system designed primarily for aggregating capacity” as a separate inclusion criteria.
3.1. Capacity Breakdown
For its reliability assessments, NERC collects two different types of capacity data to classify generators on the bulk power
system: 1) nameplate/installed capacity, and 2) seasonal rated capacity.
The nameplate (or installed) capacity of a generation resource is defined as the maximum output (usually in MW) the
resource can achieve under specific conditions designated by the manufacturer. Nameplate capacity usually does not
include resource uprates (i.e., upgrades made to the generator to increase output) or derates and capacity reductions for
station or auxiliary services and loads.
The net capacity (for both summer and winter seasons) is the maximum output (MW) a generator can supply to system
load at the time of summer or winter peak demand. The net capacity includes resource uprates (upgrades) and/or derates
and capacity reductions for station/auxiliary services. However, net capacity values can be impacted by market conditions,
environmental regulations, and other factors.
Based on data from the 2010 Long‐Term Reliability Assessment, there are approximately 13,699 generating resources in the
United States that can be broken down into different classes based on the capacity (MW) of the resource.
Less than 10 MW: 5,288 resources (39%)
Between 10 MW and 99.9 MW: 5,320 resources (39%)
Between 100 MW and 499.9 MW: 2,636 resources (19%)
Greater than 500 MW: 455 resources (3%)
Figure 2 shows an aggregation of nameplate capacity of generating resources (MW) by the number of units.
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3. Technical Justification for Generator Thresholds
Figure 2: Number of Generating Units by Nameplate Capacity (MW)12
Further analysis was developed to identify the amount capacity and number of units currently in the BES (in the U.S. only)
based on the EIA‐860 form. In addition to the current threshold level, a two other thresholds were developed as a reference
to understand what the associated impacts would. These included setting a threshold for plants and units that were above
20 MW and another for 75 MW. The analysis is included below:
Figure 3a: Number of Generating Units by Nameplate Capacity (MW)13
12
13
Data source is 2010 Long‐Term Reliability Assessment
Data source is 2010 Long‐Term Reliability Assessment
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3. Technical Justification for Generator Thresholds
The analysis shown in Figure 2a used the following assumptions:
• EIA‐860 Data (2011 Existing Unit Level Information)
Covers the 48 U.S. States
Nameplate Rating
Excludes Inoperable Units (i.e., mothballed)
Excludes units less than 1 MW (≈1,600 MW, 2,800 Units)
Excludes units “not connected to the transmission grid” (≈5,000 MW)
3.2 Alternatives to the 20/75 MVA Threshold
The PC explored multiple alternatives regarding the generator thresholds contained in the proposed Bulk Electric System
definition and selected the following five alternatives for further analysis and consideration:
3.2.1 Technical Alternative A
Description: All generation resources directly connected to the bulk power transmission system, regardless of capacity
value (MW), generator size (MVA), or voltage at the point of interconnection, to be considered part of the BES. This
alternative would not include photovoltaic resources or wind turbines connected directly to distribution systems.
Technical Discussion: Setting a small capacity value of generator resources for modeling with well‐defined points of
interconnection at BES voltage levels would not require significant changes in the way generation is recognized in
simulation models. The difficulties associated with representing small generation resources at defined points of
interconnection are those of developing and maintaining reliable datasets of resource performance in an operational
environment.
Future system studies will most likely be concerned about the cumulative behavior of new “classes” of generation, where a
class is made up of a large number of very small generating resources (which could include different types of resources
from rooftop solar systems). These generating resources will most likely have the following characteristics:
no readily identifiable point of interconnection with the BES;
capacity that will be combined with demand from nearby loads; and
generating resources making up the class will be so small, their locations and ownership so diverse, and their
technical details so varied, that explicit representation within system models in the traditional equipment‐based
sense will be impossible.
There may be areas where the aggregate output and the operating performance of small generating resources are essential
to maintaining BES reliability.
In 1997, WECC began recognizing motor behavior as it found that a large amount of its load was electric motors. Recent
technical reference paper on the FIDVR phenomenon14 is developing modeling of new classes of load whose cumulative
behavior is of great importance to the grid. The approach recognizes that it is necessary to represent the basic physical
characteristics of device class but that it is impractical to get this representation by modeling individual facilities.
It would be a natural extension of composite load modeling to recognize that a class, or classes, of distributed small
generating resources can have a cumulative impact on the reliability of the BES. The PC does not consider setting a small
(e.g., 1 MW) generator threshold to be practical from engineering and administrative perspectives. Therefore, the PC does
not recommend this alternative.
14
http://www.nerc.com/docs/pc/tis/FIDV_R_Tech_Ref_V1‐1_PC_Approved.pdf
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3. Technical Justification for Generator Thresholds
3.2.2 Technical Alternative B
Description: Technical Alternative B would require the development of either a uniform generator performance criterion or
the development of a uniform method to assess a generator’s potential impact on the reliability of the BES and determine
whether a generator should be considered part of the BES or excluded from the BES.
Technical Discussion: The draft whitepaper “Generation Exclusion Below 75 MVA in BES Definition – Position Paper”
developed by the BES Standard Drafting Team was considered in this assessment. Various case studies identified in the
paper only considered steady‐state conditions, in effect testing the deliverability of the resources dispatched in place of the
generation being removed. It would be expected to find minimal issues using this method. And, if this method or a similar
method is applied to select large generating resources, the results are expected to be similar.
Several experts in the field of dynamic simulation studies, including John Undrill, PhD,15 were consulted on potential
methods to determine a generation threshold based on a study of dynamic simulations. These methods would require the
development of specific criteria based on engineering judgment that could vary between interconnections. Based on the
confluence of feedback from technical experts, no clear technical rationale was identified to establish a minimum generator
threshold criterion. Therefore, the PC does not recommend this alternative.
3.2.3 Technical Alternative C
Description: Technical Alternative C would change the proposed Inclusion I2 to include all generating resource(s) whose
nameplate ratings are greater than 20 MVA. This would include generating resources where the generator terminals
through the high‐side of the step‐up transformer(s) are connected at a voltage of 100 kV or above.
Technical Discussion: The PC considered enhancing Inclusion I2 of the proposed BES definition by eliminating the
distinction between individual and aggregate generating facilities and selecting a single bright‐line registration criterion,
such as 20 MVA. This would modify the proposed Inclusion I2 as shown below and remove Inclusion I4:
“Inclusion I2 consisting of generating resources(s) with individual or aggregate nameplate rating greater than 20
MVA including the generator terminals connected through the high side of the step‐up transformer(s) at a voltage
of 100 kV or above.”
From a policy perspective, a single criterion of 20 MVA is greater than the data requirements currently imposed by the U.S.
Energy Information Administration Form EIA‐860,16 which collects generator‐level specific information about existing and
planned generators at electric power plants with 1 MW or greater of combined nameplate capacity. In addition, a 20 MW
generator threshold value is supported by FERC in Order 200617 and by NERC GADS.18
The PC has concluded that there is no technical rationale for having a generator threshold value for a single resource and a
different threshold value for a group of resources at a plant or facility. The potential impact to the BES for the loss of a
single generating resource or a plant or facility at the same generation level would be similar. Therefore, the same
generation threshold should apply to a single generating resource as to a plant or facility. However, there is also no
technical rationale that has been identified at this time in order to establish a single generator threshold value, whether
that value represents a single unit or a total plant. Therefore, this alternative is not recommended.
3.2.4 Technical Alternative D
Description: Technical Alternative D would seek to define BES generation resources based on physical or contractual
characteristics.
15
John Undrill, PhD is an IEEE Fellow, a member of the National Academy of Engineering: http://www.nae.edu/42087.aspx and is a
Research Professor at the Arizona State University School of Electrical, Computer, and Energy Engineering:
http://engineering.asu.edu/ecee/eceeresearchfaculty
16
Form EIA‐860 detailed data request: http://www.eia.gov/electricity/data/eia860/index.html
17
Standardization of Small Generator Interconnection Agreements and Procedures Docket No. RM 02‐12‐000 paragraph 75:
http://www.ferc.gov/eventcalendar/files/20050512110357‐order2006.pdf
18
NERC GADS’ minimum reporting threshold is greater than or equal to 20 MW starting in January of 2013.
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3. Technical Justification for Generator Thresholds
Technical Discussion: The PC considered Technical Alternative D in an effort to define BES generation resources based on
their physical or contractual characteristics. These characteristics include:
Generation resource connection voltage to the BES;
Capacity obligations of the generation resource;
Nameplate capacity of the generation resource (using U.S. Energy Information Administration (EIA) reporting
threshold of greater than 1 MW);
The inertia constant of the generation resource; and
Using Adequate Level of Reliability metrics to determine generation resource contributions to reliability.
The PC determined that establishing a generator threshold criterion based on characteristics that may change over time or
characteristics that may be considered vague would not be practical and would lack technical merit. Therefore, the PC does
not recommend this alternative.
3.3 Recommendation for Generator Thresholds
The PC recommends maintaining the currently proposed Inclusion I2 that consists of generating resources with gross
individual nameplate rating greater than 20 MVA or gross plant or facility aggregate nameplate rating greater than 75 MVA,
including the generator terminals through the high side of the step‐up transformer(s) connected at a voltage of 100 kV or
above.
The PC also recommends maintaining the currently proposed Inclusion I4, which identifies as part of the Bulk Electric
System dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating), utilizing a system designed primarily for aggregating capacity, connected at a common point at a voltage of 100 kV
or above.
The PC has not found a superior technical justification to support a different threshold.
In making these recommendations, the PC recognizes that the technical impact on reliability of a given amount of
generation at a single point in the bulk power system is the same whether the generation comes from a single unit or is the
combined output of a total plant. The PC also realizes that it would be impossible to determine a single megawatt threshold
that would apply universally. For example, based on the functions a generator provides, reactive capability and voltage
stability support, and on the characteristics of other generation located within the same region, a 20 MW unit in Florida
may not be necessary for the reliability of the bulk electric system, whereas a 20 MW unit in Quebec may. Therefore, the PC
recommends that in addition to maintaining the current 20/75 MVA thresholds, the results of applying this portion of the
BES definition should be closely monitored to evaluate the number of inclusions and exclusions, as well as technical
exception requests, and use the results of this evaluation to consider future adjustments to these thresholds.
The PC supports having different MW thresholds for the size of single units and for the combined output of plants. Further,
given the unit sizes and numbers of units shown in Figure 2a above, the PC believes that the 20 MVA threshold for single
units is still appropriate, as it encompasses over 97 percent of the capacity in the U.S. Based on EIA‐860 data (2011 existing
unit level information for the U.S.), the current 20/75 MVA thresholds will initially exclude approximately 31,000 MW of
capacity from the bright‐line definition, which represents 2.7 percent of the total capacity. Raising the unit threshold to 75
MVA would exclude an additional 35,000 MW of capacity, bringing the total capacity excluded from the bright‐line
definition to 65,000 MW, which represents 5.8 percent of the total capacity in the U.S. Similar results can be assumed if
Canadian resources are included in the analysis.
Generators in the 20 to 75 MVA range significantly contribute to the voltage and reactive support of the system; this is also
true for sub‐20 MVA units. The PC also recognizes that there may be situations in which representing units and plants
below the 20/75 MVA thresholds in modeling studies is critical to the accuracy of those studies. Many such units are small
combustion turbines or low‐head hydro units. The small hydro units tend to be older, 0.85 power factor machines, giving
them strong reactive support capabilities. Excluding such units from powerflow and dynamics studies can result in changing
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3. Technical Justification for Generator Thresholds
flow patterns, potential overloads, and understating transfer capabilities. For instance, the many small hydro units in
Maine contribute significant voltage support and stability contributions in the calculations of transfer capability from New
Brunswick into New England; removing them from the calculations reduces that transfer capability.
Finally, it would be impossible to determine a single MVA threshold that would apply universally under all conditions and in
all situations. The threshold above which generators are necessary for reliable operation of the interconnected system
would vary for different reliability concerns; e.g., voltage regulation versus rotor angle stability versus frequency response.
In addition, for any given reliability concern, the threshold would vary depending on the characteristics of the system to
which the generators are connected.
Therefore, the PC recommends that in maintaining the current 20/75 MVA thresholds, if owners of units above 20 MVA
believe that they do not have a material impact on the reliability of the bulk power system, the NERC Rules of Procedure
provide a mechanism to request an exception. The results of applying this portion of the BES definition should be closely
monitored to evaluate the number of inclusions and exclusions, as well as technical exception requests, that occur and use
the results of this evaluation to consider future adjustments to these thresholds.
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4. Technical Justification for Reactive Device Threshold
4. Technical Justification for Reactive Device Threshold
4.1 Background
Inclusion I5 specifically includes reactive devices in the definition of Bulk Electric System, Phase 1 as follows:
I5 – Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high‐side voltage of 100 kV or higher, or
through a transformer that is designated in Inclusion I1.
Inclusion I5 does not possess a threshold in terms of reactive resource sizing. As a result, all reactive resources connected at
100 kV or higher are automatically included in the BES definition regardless of their nameplate rating if they are not
excluded in E4. This results in devices such as STATCOMs, SVCs, and reactive devices connected to the tertiary windings of
BES transformers being included.
Neither the core definition nor Inclusion I5 provides a threshold for reactive device exemption; however, Exclusion E4
provides an exemption for reactive devices installed specifically for customer reactive support.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
The System Analysis and Modeling Subcommittee (SAMS) was tasked with determining an appropriate reactive threshold
for excluding some reactive devices from the BES.
Consideration of reactive support and its control are fundamental to the operation of the BES; however, many reactive
resources are located on sub‐100 kV systems (e.g., the low side of power transformers in subtransmission or distribution
substations), where they can more effectively supply the reactive demands of the load, and where they are often less
expensive to install and maintain. Reactive resources compensate for the reactive demands of loads by correcting their
power factor. Load power factor correction offsets or eliminates the reactive demand of these loads on the BES so that the
BES is only required to provide real power to the load. While sub‐100 kV reactive resources may not necessarily be integral
to BES operation, they still decrease reactive demands on the BES, which benefits the reliability of the BES by reducing
losses, supporting voltage, and freeing up capacity on the transmission system.
Furthermore, some reactive resources are connected at varying voltage levels (including sub‐100 kV). Their primary
function is to provide reactive support and voltage control. These reactive resources have a direct impact on the reliable
operation of the BES, and it is important to consider them as integral components of the BES.
4.2 Alternatives to the Zero-Mvar Threshold under Consideration
The PC explored multiple alternatives regarding the reactive device thresholds contained in the proposed Bulk Electric
System definition and selected two alternatives for further analysis and consideration.
4.2.1 Technical Alternative A
Description: This alternative would provide a threshold for excluding reactive devices sized below a value based on the
generator inclusion threshold (Inclusion I1). Since generators below 20/75 MVA are excluded, a similar or related threshold
could be to exclude reactive devices with Mvar capabilities equal to those of a 20 MVA generator.
Technical Discussion: The PC considered a threshold for reactive resources for exemption from the BES based on the typical
reactive output of a 20 MVA machine (i.e., using generator bright‐line criteria in Phase 1 of BES project).
Currently, 20 and 75 MVA thresholds exist for the inclusion of generation resources depending upon individual unit or
aggregate plant nameplate capacities, respectively. A similar approach could be taken for reactive resources; by examining
the reactive capability of a 20 MVA generator, say 0.8 per unit nameplate at maximum capacity, a value of 12 Mvar could
be selected. Alternatively, if the range of typical reactive output is considered, say at 0.85 power factor, a value of 10.5
Mvar could be selected.
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4. Technical Justification for Reactive Device Threshold
However, without a clear technical justification for the generator threshold, and considering potential inconsistencies
between the two thresholds given that generators and reactive devices have different primary objectives, extending the
generator threshold to reactive resources does not have a sound technical basis. Reactive resources are not installed for the
same reason that generation is installed (i.e., providing real power to support loads), and they are typically only installed as
required for voltage support of reliable power system operation. Therefore, the PC does not recommend this alternative.
4.2.2 Technical Alternative B
Description: This alternative examines the deployed reactive resources as modeled in interconnection power flow modeling
cases to determine whether there is a bright line to be drawn between load‐compensating resources and BES‐supporting
resources.
Technical Discussion: In examining transmission system power flow models, reactive devices installed with the sole intent
of supporting local load power factor are typically netted into the load as non‐BES Elements. Other devices are modeled
explicitly so that the effect of their statuses can be taken into account when performing system studies. By reviewing the
system modeling cases and evaluating the size of devices present in the model, a lower limit might be determined for the
reactive devices that directly support reliable BES operation.
When corresponding with generator thresholds, simply selecting a class of reactive devices based on their distribution
throughout the transmission system does not provide a sound technical justification for the selection of a threshold.
However, the Eastern Interconnection Reliability Assessment Group modeling case demonstrated that if a reactive
threshold of 10.5 Mvar were selected (corresponding to the previously mentioned generator threshold of 20 MVA at 0.85
power factor) roughly 5% of the reactive devices less than 10.5 Mvar would be directly connected at 100 kV and above
(exclusive of generators). This 5% represents a small but significant number of reactive devices—significant because they
provide critical voltage support to the reliability of the bulk power system.
It is difficult to discern whether a small reactive device is required for reliability or for other purposes. Therefore, applying
the BES exception process to exclude a subset of this relatively small class of Elements on a case‐by‐case basis is preferable
to providing a blanket exclusion for all reactive devices of this class. Further, it is consistent with a bright‐line approach.
Also, the interconnection modeling cases may not show the detail of all reactive resources on the transmission system. This
is attributed to equivalencing and reactive supply/load netting within the model. As a result, the cases may be unreliable
sources of data for obtaining the actual number and sizes of reactive devices physically installed on the interconnected
transmission system. It can be argued that even load‐netted reactive devices could have a significant impact on BES
reliability if placed in or out of service inappropriately.
Therefore, the PC does not recommend this alternative.
4.3 Conclusion and Recommendation
Reactive resources do not serve the same primary purpose as generating resources and are typically installed at BES
voltages as needed to support reliable BES operation. Inclusion I5, in its current state, provides an inherent bright‐line
distinction between devices installed to support the BES and devices installed at lower voltages to supply the reactive
component of the load (e.g., load power factor correction). Inclusion I5 includes any reactive resource directly connected at
100 kV or above, regardless of its design, configuration of its connecting facility, or planned operation.
The PC agrees that devices included by Inclusion I5 are installed to support the BES and therefore should be included. A
threshold of zero Mvar for exemption is recommended since reactive devices of all sizes can be installed for the purpose of
meeting the NERC TPL standards, and a zero‐Mvar threshold ensures that all reactive resources connected at BES voltages
(including those located in radial systems and local networks) are included.
Reactive resources connected at 100 kV or higher can be excluded on a case‐by‐case basis through the BES exception
process in the Rules of Procedure. This is consistent with other components of the bright‐line BES definition (e.g.,
generation and blackstart units) in that the potential exists for standalone BES Elements. Furthermore, Exclusion E4
provides for exemption of end‐use customer‐owned devices, which should capture most—if not all—of the reactive
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4. Technical Justification for Reactive Device Threshold
resources installed at BES voltages for the purposes of power‐factor correction (i.e., not explicitly installed to support
reliable BES operation).
Proposing a non‐zero Mvar threshold for exemption or including reactive resources below 100 kV would add unnecessary
complexity to the current bright‐line inclusion. The current wording of Inclusion I5, taken in tandem with Exclusion E4,
provides clear guidance on what is considered integral to BES reliability.
Therefore, the PC recommends maintaining the current threshold stated in Inclusion I5.
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5. Technical Justification for Power Flow Out of Local Networks
5. Technical Justification for Power Flow Out of Local Networks
5.1 Background
Exclusion E3 provides an exemption for “local networks” in the definition of Bulk Electric System, Phase 1 as follows:
E3 – Local networks (LN): A group of contiguous transmission Elements operated at or above 100 kV but less than 300
kV that distribute power to Load rather than transfer bulk power across the interconnected system. LNs emanate from
multiple points of connection at 100 kV or higher to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LN is characterized by all of the following:
Limits on connected generation: The LN and its underlying Elements do not include generation resources
identified in Inclusion I3 and do not have an aggregate capacity of non‐retail generation greater than 75 MVA
(gross nameplate rating);
Power flows only into the LN, and the LN does not transfer energy originating outside the LN for delivery
through the LN; and
Not part of a flowgate or transfer path: The LN does not contain a monitored facility of a permanent flowgate
in the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable
monitored facility in the ERCOT or Québec Interconnections, and is not a monitored facility included in an
Interconnection Reliability Operating Limit (IROL).
The intent of defining an LN is to provide an exemption for components of transmission systems that were installed to
improve the level of service to retail customer Load. An LN’s design and operation is intended to be such that, at the points
of connection to the BES, the LN’s effect on the BES is similar to that of a radial system (i.e., as in Exclusion E1), particularly
with regard to the fact that in aggregate, real power flow always flows from the BES into the LN. Any re‐distribution of
parallel flows into the LN from the BES will be negligible compared to the load being served by the LN. Furthermore, since
the primary purpose of an LN is to improve the level of service to retail customer Load, and not to support the reliable
operation of the interconnected BES, the separation of an LN from the BES shall not diminish the reliability of the BES.
In other words, an LN can effectively be treated in the same way as a radial system but with multiple feeds that enhance
local reliability or meet customer requirements, and as such, the characteristics of an LN should match those of a radial
system as closely as possible.
The wording of Exclusion E3 raises two issues related to the phrase “power only flows into the LN”:
1) The wording “power only flows into the LN” can be strictly interpreted as meaning that no power will flow out
of any connection point of the LN, at any time. While power may not flow out of an LN during normal
conditions (e.g., LNs are not permitted to wheel power), the potential exists for parallel flows following a
contingency event (i.e., single, double, etc.).
2) The following questions also arise: Should there be a distinction between real and reactive power flow? Does
the limitation that “power only flows into the LN” also imply that reactive power is absorbed by the LN at all
points of interconnection and at all times?
With regard to these issues, the PC was tasked with providing a threshold for permissible flow out of an LN, along with
appropriate time duration for outward flows and the associated system conditions. Specifically, the problem statement is:
“It is anticipated that the technical justification will consist of interconnection‐wide studies that target the surrounding
BES Elements at the connection points of the subject LN. The studies would utilize the criteria currently established
within the definitions of Adequate Level of Reliability19 and Adverse Reliability Impact20 to determine the appropriate
19
From the NERC Glossary of Terms, Adverse Reliability Impact: “The impact of an event that results in frequency‐related instability;
unplanned tripping of load or generation; or uncontrolled separation or cascading outages that affects a widespread area of the
Interconnection.”
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5. Technical Justification for Power Flow Out of Local Networks
values for the thresholds associated with the potential power flow out of the LN. The final analysis should indicate the
amount of acceptable parallel flow through an LN where a loss of the LN or portions of the LN would not result in a
reduction of the reliability of the surrounding interconnected Transmission network.”
In addition to the issues described above pertaining to the allowable flow through an LN, the PC concluded that the BES
definition would greatly benefit from a bright‐line distinction for the maximum allowable size (i.e., a maximum MW load
limit) of an LN, and in such a way that a system cannot be subdivided into multiple adjoining LNs. In other words, the
definition should not allow multiple LNs to be directly tied to one another, nor should it allow for LNs to be embedded or
nested within one another. If large amounts of load are not properly taken into account across an interconnection due to
exclusion as LNs, then significant impacts to BES reliability—such as frequency stability issues and system operating limit
violations—could result due to separation of an LN from the BES.
Prior to the adoption of the Phase 1 BES definition, there were significant regional differences in both the definition of BES
and its application that permitted exclusions for portions of a load‐serving transmission network. The Phase 1 definition’s
Exclusion E3 for LNs is intended to standardize this exclusion for systems that are often referred to as “load pockets” along
with the Transmission Elements that connect them (assuming that the Transmission Elements are all operated at voltages
of at least 100 kV but less than 300 kV, and assuming the underlying generation inclusions and exclusions are met).
However, the interaction between an LN and the BES needs to be carefully considered. Providing exclusion for LNs
regardless of size could lead to the exclusion of very large networks, which could affect BES reliability. The loss of large
networks could have far‐reaching, interconnection‐wide system impacts.Selecting a bright line for load that can be served
by an LN will limit the unintended consequences of such exclusions, and, if needed, the exception process in the Rules of
Procedure provides a path for exemption of larger LNs.
5.2 Alternatives to the Zero Power Flow Limitation under Consideration
The PC explored multiple alternatives regarding power flow out of LNs contained in the proposed Bulk Electric System
definition and selected three alternatives for further analysis and consideration.
5.2.1 Technical Alternative A
Description: This alternative would propose an acceptable amount of outward power flow for LNs that would be consistent
with generation limits set forth elsewhere in the BES definition.
Technical Discussion: The PC considered generation limits set forth elsewhere in the BES Phase 1 definition to define an
acceptable amount of outward power flow for LNs. For example, applying a limit on outward flow from an LN
corresponding with the 75 MVA embedded generation maximum would provide consistency with the radial system
Exclusion E1.
With radial systems, the outward flow of power will always occur at a single connection point on the BES. However, with an
LN, outward flow of generation may occur at any terminal on the LN. Without knowing or considering the internal
conditions within the LN, outward flows may lead to unpredictable impacts to the overlying BES. Furthermore, without a
clear technical justification for the generator threshold, extending this threshold to LNs does not have a sound basis.
Therefore, the PC does not recommend this alternative.
20
Currently under development for inclusion in the Glossary of Terms, Adequate Level of Reliability: “The intent of the set of NERC
Reliability Standards is to deliver an Adequate Level of Reliability defined by the following bulk power system characteristics:
The system is controlled to stay within acceptable limits during normal conditions.
The system performs acceptably after credible contingencies.
The system limits the impact and scope of instability and cascading outages when they occur.
The system’s facilities are protected from unacceptable damage by operating them within facility ratings.
The system’s integrity can be restored promptly if it is lost.
The system has the ability to supply the aggregate electric power and energy requirements of the electricity consumers at all
times, taking into account scheduled and reasonably expected unscheduled outages of system components.”
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5. Technical Justification for Power Flow Out of Local Networks
5.2.2 Technical Alternative B
Description: This alternative considers the use of outage transfer distribution factors (OTDFs) to define a threshold for an
acceptable amount of through‐flow on LNs.
Technical Discussion: OTDFs represent the percentage of a power transfer that flows through the monitored facility for a
particular transfer when the facility is switched out of service after a contingency. In relation to an LN, the monitored
facilities would include the terminals of the LN, and the contingent facilities would include BES Elements in parallel with the
local network. The Flowgate Methodology described in MOD‐030‐2 sets a 5% threshold for OTDF, in conjunction with other
criteria for including a monitored facility as a flowgate. In a similar fashion, an OTDF of 5% or less could be selected as a
reasonable threshold for defining the permissible flow through an LN upon the occurrence of a BES contingency, and
subsequently for determining a reasonable amount of flow out of an LN.
While computation of OTDFs and related factors are commonplace calculations and well‐understood, such factors do not
necessarily form a bright line for exclusion from the BES; the permitted flow computed in the OTDF will depend on the
contingent Element and will be heavily dependent upon system conditions. Appropriate system conditions and
contingencies would need to be specified. This would complicate the definition and completion of supporting analysis and
potentially lead to inconsistencies in the application of this approach.
Therefore, the PC does not recommend this alternative.
5.2.3 Technical Alternative C
Description: This alternative would use the existing definition, along with clarifications, to identify the circumstances under
which power is expected only to flow into an LN.
Technical Discussion: This alternative relies on the existing Exclusion E3 and, while preserving the concept of an LN,
proposes clarification without confusing the bright‐line distinction between an LN and the BES. The recommended changes
to Exclusion E3 item (b) are given below in bold:
Real power flows only in the LN from every point of connection to the BES for the system as planned with all‐
lines in service and also for first contingency conditions as per TPL‐001‐2, Steady State & Stability Performance
Planning Events P0, P1, and P2, and the LN does not transfer energy originating outside the LN for delivery
through the LN to the BES.
The PC considered specifying that both real and reactive power must flow into the LN. The “real power” clarification is
recommended to align with the recommendation on Inclusion I5 for an appropriate reactive device threshold; if all reactive
devices connected directly at 100 kV and above are included in the BES definition, then their impact to reliability will be
accounted for independently of Exclusion E3. In this case, an LN may deliver some reactive power to the BES in the same
way that, under some conditions, a load‐serving distribution network delivers reactive power to the BES.
The PC recommends adding the words “from every point of connection to the BES” for clarity. If real power flows out of
the network at any interconnection point under normal conditions or single‐contingency conditions, then at least some
portion of the LN is being used to transfer power to the overlying BES network. The portions of a proposed LN that allow
parallel flow must be removed from the LN, and the remaining portions of the proposed LN should be further studied to
ensure that they do not participate in such flows.
Limiting the study of a proposed LN “for the system as planned” (i.e., over the planning horizon) is recommended. This
allows some flexibility for outward flow under abnormal or unplanned conditions.
The “single contingency” wording is also recommended for clarity. The intent would be to study single contingencies on the
BES outside of the LN, as well as contingencies within the LN, and to monitor the LN for any outward flow under these
conditions. The PC understands that the system is planned for multiple contingencies; however, the expectation of real‐
time performance for multiple contingencies under myriad unplanned system operating conditions is much more difficult to
define. The study of multiple contingencies requires closer examination of credible contingencies. To avoid creating a very
complex LN definition, the PC selected “single contingency,” because existing NERC Reliability Standards call for the system
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5. Technical Justification for Power Flow Out of Local Networks
to be operated to single‐contingency conditions. Including a single‐contingency requirement would imply that the definition
of LN would hold under NERC‐mandated operating conditions. The threshold is zero power out of the LN—what is being
clarified are the conditions under which that threshold applies.
The single‐contingency load flow test should not be burdensome to administer. First, contingency analysis is required to be
performed annually as part of the TPL requirements. The purpose of basing the determination on the planning horizon is to
preserve the bright line so that the facilities can be characterized as they are planned to be operated. Clarifying the
definition in such a manner avoids the need to constantly reclassify Elements in response to the myriad of operating
conditions that may occur on the system.
5.3 Conclusion and Recommendation
The PC recommends using Technical Alternative C, which proposes changes that clarify the existing Exclusion E3. The
recommended changes to Exclusion E3 item (b) are given below in bold:
Real power flows only in the LN from every point of connection to the BES for the system as planned with all‐lines in
service and also for first contingency conditions as per TPL‐001‐2, Steady State & Stability Performance Planning
Events P0, P1, and P2, and the LN does not transfer energy originating outside the LN for delivery through the LN to
the BES.
The PC further suggests that a size limit be established in the LN definition to prevent the exclusion of large networks that
may have a significant impact on reliable BES operation. This recommendation is explained in detail in the following section,
as well as in Appendix 3.
5.4 Further Considerations for Limits on the Size of Local Networks
In determining the connected MVA bright‐line value for the size of LNs, NERC Reliability Standard EOP‐00421 Disturbance
Reporting could be used as a starting value for inclusion or exclusion. Attachment 1 of EOP‐004 indicates the magnitude of
firm demand loss during disturbances that are of concern and require reporting to NERC. Attachment 1’s relevant text is as
follows:
Equipment failures/system operational actions that result in the loss of firm system demands for more than 15
minutes, as described below:
o
Entities with a previous year recorded peak demand of more than 3,000 MW are required to report all
such losses of firm demands totaling more than 300 MW.
o
All other entities are required to report all such losses of firm demands totaling more than 200 MW or
50% of the total customers being supplied immediately prior to the incident, whichever is less.
A review of interconnection facilities serving approximately 300 MW of load determined that the system consisted of 800–
900 MVA of interconnection capability to maintain the reliability of the interconnected system. This capability over the load
value is usually installed for N‐1 planning criteria, and support of this assumption is justified in a review of average circuit
loadings on the system.
As an example, an entity with a peak load of approximately 4,500 MW calculated an average circuit loading on their system
to be approximately 23.6%. Using this average circuit‐loading approach determined that an additional 1,271 MVA of
interconnecting MVA capacity would be required to serve 300 MW of load. Using 800 MVA for substations with
interconnecting capability is a conservative estimate.
As another example, transmission lines with 400 MVA of transfer capability would calculate to the approximate values:
2,000 amps at 115 kV
1,674 amps at 138 kV
21
NERC Reliability Standard EOP‐004: http://www.nerc.com/files/EOP‐004‐1.pdf
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5. Technical Justification for Power Flow Out of Local Networks
1,434 amps at 161 kV
1,004 amps at 230 kV
670 amps at 345 kV
The selection of 400 MVA for a single‐circuit bright‐line test is that most system configurations do not rely on a single circuit
to serve 300 MW of load, but rather use multiple, lower rated facilities. Therefore, a rating above 300 MVA would be
appropriate for a single transmission line.
The PC suggests the addition of a gross load limit in the form of another qualifier under Exclusion E3:
The gross load served by the LN is less than 300 MW.
The addition of this limit on local networks will ensure that the systems that support metropolitan areas will not be
excluded by default. As with other bright lines established in the BES definition (e.g., 100 kV core definition and 20/75 MVA
generator thresholds), this specific number was selected to clearly categorize networks and Elements to prevent significant
adverse impacts to the BES in a way that can be applied consistently across power systems, Regions, and interconnections.
The PC identified the 300 MW limit based on a preponderance of evidence presented by a cross section of regional
representation that is supported by the following data points:
U.S. Department of Energy Electric Disturbance Events form OE‐41722 and NERC Standard EOP‐004 provide a
bright‐line criteria of 300 MW for reporting load loss.
The typical upper limit of a radial system reported by SAMS members was approximately 100 MW. The upper limit
on the maximum consequential load loss reported by SAMS members was less than 300 MW.
Examination of 100–300 kV line ratings across the interconnections shows that the majority are rated less than 300
MW (see Table 2 and Appendix 3). Flows on transmission lines are typically a fraction of the line rating (i.e., this is
an upper bound), and the system is required to tolerate the flow shifts created by a single contingency (i.e., a line
outage); therefore, an LN should not have the potential to induce a greater shift in flow.
Table 2: Summary Statistics for Branches in 2010 Power Flow Models
Mean
(MW)
Median
(MW)
Standard Deviation.
(MW)
Maximum
(MW)
Minimum(MW)
Percent of lines
rated < 300 MW
(%)
ERAG
WECC
ERCOT
266.6
233.9
289.1
216.0
159.0
228.0
181.6
202.5
144.6
1800.0
3031.1
1220.0
7.0
12.0
12.0
73.9
76.1
62.4
Even for zero outward power flow as allowed in the LN definition, this 300 MW load limit could entail a change in flow of up
to 300 MW on the terminals of the overlying BES (i.e., a 300 MW swing between two terminals of the LN). A very simple
illustration based on an actual network is provided in Appendix 3. The BES and higher voltage networks and are depicted in
red, and a lower voltage network to be considered as an LN is depicted in blue.
22
The Electric Emergency Incident and Disturbance Report (Form OE‐417) collects information on electric incidents and emergencies. The
Department of Energy uses the information to fulfill its overall national security and other energy emergency management
responsibilities, as well as for analytical purposes. http://www.oe.netl.doe.gov/oe417.aspx
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6. Recommendations
6. Recommendations
After analysis and review, the PC offers the following recommendations to the DBES SDT:
Maintain the 100 kV bright line (core definition).
Maintain Inclusions I2 and I4 as currently defined.
Maintain Inclusion I5 as currently defined.
Use Technical Alternative C, which proposes clarifying changes to the existing Exclusion E3 item (b) as given below
in bold:
Real power flows only in the LN from every point of connection to the BES for the system as planned with
all‐lines in service and also for first contingency conditions as per TPL‐001‐2, Steady State & Stability
Performance Planning Events P0, P1, and P2, and the LN does not transfer energy originating outside the LN
for delivery through the LN to the BES.
Establish a size limit in the LN definition to prevent the exclusion of large networks that may have a significant
impact on reliable BES operation. This recommendation is explained in detail in the following section, as well as in
Appendix 3.
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Appendix 1A: Request from the BES SDT to the PC
Appendix 1A: Request from the BES SDT to the PC
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Appendix 1A: Request from the BES SDT to the PC
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Appendix 1B: Authorization and Problem Statement from the BES Definition SDT (NERC Standards Project 2010‐17, Phase II)
Appendix 1B: Authorization and Problem Statement from the
BES Definition SDT (NERC Standards Project 2010-17, Phase
II)
A1.1 Background:
The ERO has the obligation to identify the Elements necessary for the reliable operation of the interconnected Transmission
network to ensure that the ERO, the Regional Entities, and the industry have the ability to properly identify the applicable
entities and Elements subject to the NERC Reliability Standards. The NERC Board of Trustees‐approved definition of the Bulk
Electric System (BES) establishes detailed criteria that allows for the identification of BES Elements in a consistent manner
on a continent‐wide basis.
During the initial revision of the definition of the BES in Phase I of Project 2010‐17, industry stakeholders expressed
concerns related to the lack of technical justification associated with the existing parameters in the definition.
A1.2 Problem Statement: Transmission Facilities and Real and Reactive
Resources:
The reliability of the interconnected transmission network is impacted by properly identified BES Elements. The ability to
properly identify BES Elements is dependent on a BES definition that is based on factors directly associated with reliability.
The NERC Board of Trustees‐approved definition of the BES utilizes historical parameters from the current NERC Glossary of
Terms definition of BES and the NERC Statement of Compliance Registry Criteria, neither of which is supported by technical
justification.
The DBES SDT is seeking support from the NERC Technical Committees (Operating and Planning) for the development of
technical justification to assist the SDT in developing potential revisions to the following parameters currently embedded in
the NERC Board of Trustee approved definition of the BES:
100 kV bright line (core definition)
Generation thresholds (Inclusions I2 and I4)
MVA values associated with single‐unit and multiple‐unit facilities
Reactive power sizing (MVA level) parameters (Inclusion I5)
It is anticipated that the technical justification will consider the criteria currently established within the definitions of
Adequate Level of Reliability and Adverse Reliability Impact, to determine the appropriate values for the thresholds
associated with the identification of Transmission Facilities and Real and Reactive Resources as BES Elements.
The SDT received the following suggestions of studies that could be utilized for these issues:
100 kV Bright Line
Western Electric Coordinating Council’s Bulk Electric System Definition Task Force (“BESDTF”), Initial Proposal and
Discussion to determine 100 kV or 200 kV threshold, at pp. 11‐18 (May 15, 2009)23
Concept of considering Surge Impedance Loading (SIL) alongside the corresponding normal thermal ratings,
whichever is less, for typical compensated/uncompensated and overhead/underground transmission lines at
various kV levels. A single MVA bright line could then act to screen which subsystem Elements fall in or out of the
BES definition.24,25
23
http://www.wecc.biz/Standards/Development/Lists/Request%20Form/DispForm.aspxID=21&Source=/Standards/Development
IEEE Transactions on Power Apparatus and Systems, Vol.PAS‐98, No.2 March/April 1979 pp 606‐617, “Analytical Development of
Loadability Characteristics for EHV and UHV Transmission Lines,” as well as its referenced articles.
25
AECI related white paper prepared for the BES Definition SDT, as well as AECI’s referenced Eastern Interconnection PSEE 2011 Winter
Peak Branch‐data, with per‐unit SIL calculations, for further analysis, available from AECI upon request.
24
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Appendix 1B: Authorization and Problem Statement from the BES Definition SDT (NERC Standard Project 2010‐17, Phase II)
NPCC study presented in the NPCC/NERC 9/21/09 filing in FERC Docket No. RC09‐3‐000
Generation Thresholds and Reactive Power sizing
ISO‐NE and NYISO planning and operating study process to demonstrate loss of largest source without Adverse
Reliability Impact to the Bulk Electric System.
Snohomish County PUD White Paper entitled “A Performance‐Based Exemption Process to Exclude Local
Distribution Facilities from the Bulk Electric System” (April 2011) discusses a methodology for distinguishing BES
from non‐BES Elements based on their performance in the electric system.
Project 2007‐09 for proposed standard MOD‐026 developed generation modeling thresholds.26
Draft white paper for possible exclusion of generators from BES as submitted to the DBESSDT.
A1.3 Local Networks:
Local networks (LN) (Exclusion E3) provide local electrical distribution service and are not planned, designed, or operated to
benefit or support the balance of the interconnected transmission network. Their purpose is to provide local distribution
service, not to provide transfer capacity for the interconnected transmission network. Their design and operation is such
that at the point of connection with the interconnected transmission network, their effect on that network is similar to that
of a radial facility, particularly in that flow always moves from the BES into the LN. As governed by the fundamentals of
parallel electric circuits, any distribution of parallel flows into the LN from the BES is negligible, and, more importantly, is
overcome by the Load served by the LN, thereby ensuring that the net actual power flow direction will always be into the
LN at all interface points. An LN is not intended to enhance the operability of the interconnected transmission network;
therefore, its separation from the BES will not diminish the reliability of the interconnected transmission network.
The NERC Board of Trustees‐approved definition of the BES identifies the characteristics, based on the bright‐line concept,
which establishes specific criteria that must be met to allow an LN to be excluded from the BES. One such characteristic
identifies the threshold associated with power flows and states:
Power flows only into the LN, and the LN does not transfer energy originating outside the LN for delivery through
the LN.
This requirement assumes that the condition (power flows only into the LN) will have to be met at each connection point of
the LN. The SDT is seeking support from the NERC Technical Committees (Operating and Planning) for the development of
technical justification to potentially revise the power flow provision (including duration and system conditions) identified in
Exclusion E3 of the NERC Board of Trustees‐approved definition of the BES.
It is anticipated that the technical justification will consist of interconnection‐wide studies that target the surrounding BES
Elements at the connection points of the subject LN. The studies would utilize the criteria currently established within the
definitions of Adequate Level of Reliability and Adverse Reliability Impact to determine the appropriate values for the
thresholds associated with the potential power flow out of the LN. The final analysis should indicate the amount of
acceptable parallel flow through an LN where a loss of the LN or portions of the LN would not result in a reduction of the
reliability of the surrounding interconnected transmission network.
26
http://www.nerc.com/files/Project_2007‐09_Generator_Verfication_PRC‐024_and%20MOD‐026.pdf
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Appendix 1C: BES SDT Response to PC Report (Draft 2012 BES definition report)
Appendix 1C: BES SDT Response to PC Report (Draft 2012 BES
definition report)
Note: The report, Generation Threshold Sub‐Team Report, January 2013, is not publically posted at this time.
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Appendix 2: Interconnection Study Guidelines
Appendix 2: Interconnection Study Guidelines
A2.1 Eastern Interconnection Study
In the Eastern Interconnection (EI), ERAG annually develops power flow models of the bulk transmission system and
performs inter‐regional transmission assessment studies on some of those models. The power flow models incorporate
varying specificity in the different transmission voltage levels, but most (if not all) of the facilities at 100 kV and above are
included.
Since its inception, ERAG has traditionally studied the transmission systems in MRO, RFC, SERC, and SPP at 100 kV and
above, because those facilities are inherently necessary to operate the Bulk Electric System. The 100–200 kV facilities are
necessary to the operation of the Bulk Electric System, because they are the substantial underlying portions (i.e., voltages
under 230, 345, 500, and 765 kV) of the rest of the BES, they carry significant portions of bulk power transfers, and they
provide a backup transfer path when higher voltage facilities (i.e., 230, 345, 500, and 765 kV) are out of service.
Without including the 100–200 kV facilities in the BES, the higher voltage (i.e. 230, 345, 500, and 765 kV) facilities would
not be able to solely, reliably carry the needed power to load without experiencing overloads, low voltages, SOLs, and
possibly IROLs, as seen in previous ERAG studies and reports.
A2.1.1 Generation
The 100–200 kV level of transmission facilities is important for the interconnection of generation. Nearly a third of the total
generation in the Eastern Interconnection is connected to the 100–200 kV level.
Table A2-1: Total Generation in Eastern Interconnection27
Total Generation in EI
884,519 MW
% of Total
Above 200 kV
565,929
64.0%
100–200 kV
249,833
28.2%
69 kV
25,472
2.9%
Below 69 kV
43,285
4.9%
A2.1.2 Load
The 100–200 kV level of transmission facilities is critical for generation to be delivered to load. Nearly a quarter of the load
in the Eastern Interconnection is connected to the 100–200 kV level.
Table A2-2: Total Load in Eastern Interconnection28
Total Load in EI
645,556 MW
% of Total
Above 200 kV
53,302
32.8%
100–200 kV
147,076
22.8%
69 kV
111,909
17.3%
Below 69 kV
174,855
27.1%
27
Data is from the ERAG 2012 Summer Peak case within the MMWG 2011 Series of power flow models.
Data is from the 2012 Summer Peak case within the MMWG 2011 Series of power flow models. Generating plant auxiliary loads are
included, if modeled.
28
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Appendix 2: Interconnection Study Guidelines
A2.1.3 Transmission Line Mileage
The BES definition should include most of the transmission that is important to deliver generation to load. A majority of the
total BES transmission line mileage is made up of 100–200 kV facilities. The total transmission miles that falls in the 100–
200 kV range is 67% of the total miles. Mileage data for the tables below was taken from the 2011 NERC Long‐Term
Reliability Assessment data submittals.
Table A2-3: Transmission Circuit Line Mileage in Eastern Interconnection
Area
100‐120 kV 121‐150 kV
151‐199 kV
Total
Area
100‐199 kV %
FRCC
2,251
2,277
0
4,528
FRCC
38%
MISO
7,606
19,071
5,778
32,456 MISO
66%
MRO
5,428
3,670
264
9,362
MRO
44%
NPCC29
19,439
3,527
138
23,104 NPCC
52%
PJM
4,911
23,120
395
28,426
PJM
54%
SERC
35,427
4,095
17,263
56,785 SERC
67%
SPP
9,082
8,729
4,801
22,612
SPP
69%
Table A2-4: Transmission Circuit Line Mileage in Eastern Interconnection
Area
200‐299 kV
300‐399 kV
400‐599 kV
600 kV+
Total
FRCC
6,095
0
1,350
0
7,445
MISO
3,022
13,117
340
0
16,479
MRO
9,801
2,041
257
0
12,099
NPCC30
11,759
8,145
1,600
160
21,664
PJM
9,148
9,417
3,816
2,206
24,587
SERC
18,383
1,577
7,473
0
27,433
SPP
3,572
6,559
114
0
10,245
A2.1.4 Transmission Assessment Study Results
Data for the tables below was taken from the ERAG summer seasonal studies listed in Tables A2‐5 and A2‐6. Many of the
limited facilities for the studied transfers are on the 100–200 kV level, which indicates that the 100–200 kV facilities are
inherent to the reliable operation of the BES.
Table A2-5: Limiting Elements in 2007 Study
Limiting Element
Contingency
2007 Study Total 100‐199 kV Percentage 200+ kV Percentage 100‐199 kV 200+ kV
MRSwS
18
17
94.4
1
5.6
4
13
SeR
8
4
50.0
4
50.0
4
6
RN
7
2
28.6
5
71.4
0
0
RFC
76
44
57.9
32
42.1
28
47
29
Quebec Interconnection (QI) is excluded. The total of NPCC when adding QI is the following: 100–120 kV: 23,731; 121–150 kV: 3,527;
151–199 kV: 1,460; Total: 28,718; 100–199 kV %: 45%
30
Quebec Interconnection (QI) is excluded. The total of NPCC when adding QI is the following: 200–299 kV: 13,733; 300–399 kV: 11,494;
400–599 kV: 2,357; 600 kV+: 7,257; Total: 34,842
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Appendix 2: Interconnection Study Guidelines
Table A2-6: Limiting Elements in 2011 Study
Limiting Element
2011 Study Total 100–199 kV Percentage 200+ kV
MRSwS
19
14
73.7
5
SeR
6
3
50.0
5
RN
2
1
50.0
1
RFC
16
6
37.5
10
Percentage
26.3
50.0
50.0
62.5
Contingency
100–199 kV 200+ kV
9
13
4
3
0
2
6
8
A2.2 Québec Interconnection
The Bulk Power System (BPS) in the Quebec Interconnection includes substations that have a 735 kV voltage level with their
connected lines and transformers. These facilities do not directly serve end‐use customers. They constitute the
transmission system and provide interfaces for moving large amounts of power from remote northern generation to load
centers in southern Québec (approximately 600 miles away). BPS assets have been identified through impact‐based studies,
using the NPCC A‐10 methodology. The Régie de l’énergie of Québec provides the regulatory oversight within the Province
of Québec, which includes the definition of the BPS and BES.
A2.3 Electric Reliability Council of Texas (ERCOT)
In ERCOT Interconnection, the Steady State Working Group (SSWG) annually develops power flow models of the
transmission system, and ERCOT staff, various ERCOT work groups, and market participants perform transmission
assessment studies on these models. The power flow models incorporate almost all utility transmission facilities operated
at 60 kV and above.
ERCOT is the smallest of the three interconnections in the United States31 and operates wholly within Texas. As the
independent organization (IO) under the Public Utility Regulatory Act (PURA), ERCOT is charged with nondiscriminatory
coordination of market transactions, system‐wide transmission planning, network reliability, and ensuring the reliability and
adequacy of the regional electric network in accordance with ERCOT and NERC reliability criteria. ERCOT’s relatively small
size and unique market structure allows it to model almost all utility transmission facilities operated at 60 kV and above.
A2.3.1 Generation
The 100–200 kV level of transmission facilities is important for ERCOT since 44% of all generation is connected at 138 kV.
Almost 99% of all the generation in ERCOT is connected at voltages above 100 kV.
Table A2-7: Total Generation in ERCOT32
Total Generation in ERCOT 74,948 MW % of Total
345 kV
41,053 MW
54.8%
138 kV
33,042 MW
44.1%
69 kV
853 MW
1.1%
A2.2.2 Load
The 100–200 kV level of transmission facilities is critical for the deliverability of generation to load. The amount of load in
ERCOT connected at 138kV is 86%.
Table A2-8: Total Load in ERCOT33
Total Load in ERCOT 73,387 MW % of Total
345 kV
987 MW
1.3%
138 kV
63,097 MW
86.0%
31
32
Considering Installed Capacity, the Québec Interconnection in Canada is smaller than ERCOT.
Data is the level of dispatched generation from the SSWG 2012 Summer Peak case within the SSWG 2011 Series of power flow models.
33
Data is from the 2012 Summer Peak case within the SSWG 2011 Series of power flow models.
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Appendix 2: Interconnection Study Guidelines
69 kV
9,304 MW
12.7%
A2.3.3 Transmission Line Mileage
The total transmission line miles in ERCOT that falls in the 100–200 kV range is 58%, and over three quarters of the line
miles operate at voltages above 100 kV. Over 22% of the physical transmission line miles in ERCOT operate at 69 kV.
However, ERCOT’s 69 KV transmission lines are predominantly in rural areas and serve small electric loads and wind plants
that are dispersed over a large geographic region. As shown in the tables above, the 69 kV system in ERCOT serves
approximately 1% of the electric load and 13% of the generation in ERCOT. The loss of the small, lightly loaded 69 kV lines
spread over a large geographic region in ERCOT do not pose a threat to the Bulk Electric System.
Table A2-9: Total Transmission Line Miles in ERCOT
Total Line Miles in ERCOT
Miles
% of Total
345 kV
9,498
18.8%
230 kV
13
0.1%
138 kV
29,349
58.3%
69 kV
11,460
22.8%
A2.3.5 Transmission Assessment Study Results
ERCOT Staff supervises and exercises comprehensive independent authority of the overall planning of transmission projects
in the ERCOT Interconnection (transmission system) as outlined in PURA and Public Utility Commission of Texas (PUCT)
Substantive Rules. ERCOT’s authority with respect to local transmission projects is limited to supervising and coordinating
the planning activities of Transmission and Distribution Service Providers. In performing its evaluation of different
transmission projects, ERCOT takes into consideration the need for and cost‐effectiveness of proposed transmission
projects in meeting the ERCOT and NERC planning criteria. Therefore, ERCOT studies regularly identify constraints at 69 kV
even though the facilities are not needed for the reliable operation of the BES.
A2.4 Western Interconnection
All facilities that have an impact on the BES should be included in the definition of the BES. The BES definition should be
easy to understand and administer. BES classification should not be a moving target. For reliability, a more inclusive
definition of the BES is desirable, rather than potentially omitting a facility that in a time of need may be necessary to
support the BES.
For the purposes of this paper, WECC base cases have been utilized. The individual Transmission Planner’s data submittals
determined the level of detail in WECC base cases. The WECC Data Preparation Manual states that Transmission Planners
should represent their systems in sufficient detail such that the impact of any disturbances, whether internal or external to
their own systems, can be adequately evaluated. The level of detail represented by the Transmission Planners should be the
same as that used by individual Transmission Planners in conducting their internal bulk transmission system studies or
facility ratings studies.
WECC respects Transmission Planners’ judgment and strongly considers it in the development of WECC base cases. Through
an analysis of WECC base cases it can be seen that Transmission Planners in WECC model a majority of the load and
generation connected to 100 kV and above. The inclusion of data in base cases indicates that this is the level of detail
needed to model the BES for power flow and stability studies.
A2.4.1 Generation
In WECC, over 80% of the generation modeled in base cases is primarily connected through generator step‐up transformers
with high‐side voltages of 100 kV and above. The table below shows that the largest portion of the generation modeled in
WECC (40%) connects between 200 and 300 kV. Total generation in WECC maintains the currently filed 100 kV bright‐line
threshold without adjustment.
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Appendix 2: Interconnection Study Guidelines
Table A2-10: Total Generation in WECC34
Total Generation in WECC 245,737 MVA % of Total
300 kV and Greater
61,274 MVA
24.93
200 to 300 kV
98,717 MVA
40.17
100 to 200 kV
42,553 MVA
17.32
50 to 100 kV
17,501 MVA
7.13
Less than 50 kV
25,692 MVA
10.45
A2.4.2 Load
The WECC base cases model load at various voltages. The table below shows that the vast majority of load is modeled
below 200 kV, with a large portion modeled between 50 and 100 kV.
Table A2-11: Total Load in WECC35
Total Load in WECC 172,750 MW % of Total
300 kV and Greater
15 MW
0.01
16,257 MW
9.41
100 to 200 kV
63,963 MW
37.03
50 to 100 kV
58,749 MW
34.00
Less than 50 kV
33,766 MW
19.55
200 to 300 kV
A2.4.3 Transmission Line Mileage
The definition of the BES should include the transmission that is critical for delivering generation to load. Of the
transmission line miles collected, over 40% of the total in WECC falls in the 100–200 kV range.
Table A2-111: Transmission Line Miles by Voltage Class36
Line Voltage kV
100‐ 199 200‐299
300‐399
400‐599
WECC (miles)
50,306
42,336
11,637
20,262
A2.4.4 Transmission Assessment Study Results
In WECC, path limits are primarily established through the WECC Rating Review Process. Path limits are set based upon
transient and post‐transient stability limits, as well as thermal limits. A review of paths that went through this process
indicates that, although most paths are limited by 345 kV and 500 kV Elements, instances exist where the transfer capability
limits are determined by facilities between 100 kV and 200 kV.
34
Note: Data is the generation available in the WECC 2012 Heavy Summer operating case within the WECC 2011 series of power flow
models.
35
Data is the load forecasted in the WECC 2012 Heavy Summer operating case within the WECC 2011 series of power flow models.
36
Data is from the 2011 Long Term Reliability Data Collection. No data collected for transmission facilities below 100 kV
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Appendix 3: Operational Considerations to Support Load Limit on Local Networks
Appendix 3: Operational Considerations to Support Load Limit
on Local Networks
The SAMS proposes to set a 300 MW maximum limit for the amount of load that may be served by a proposed local
network (LN). This limit is proposed to ensure that LNs do not affect the reliable operation of the BES.
As represented in the figure below, under normal operating conditions, a two‐terminal LN receives 220 MW on its western
terminal and 60 MW on its eastern terminal (Figure A3‐1).
Figure A3‐1: Bulk Electric System Flow through Local Network
For a single BES contingency, the flow into the LN shifts from west to east by 200 MW, so that the LN now receives 20 MW
on its western terminal and 260 MW on its eastern terminal (Figure A3‐2).
Figure A3‐2: Bulk Electric System Flow through Local Network
The 200 MW shift would be reflected in the BES and would be picked up by one of the BES transmission lines on the eastern
side of the system; this change could represent a substantial increase in load for the affected line.
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Appendix 3: Operational Considerations to Support Load Limit on Local Networks
If a gross load limit were not placed on the size of the LN, then such a shift could be much larger, and the resulting impact
to the BES could be significant. In a similar vein, consideration also may need to be given to limiting the size of a radial
system (identified in Exclusion E1) since the total loss of load in the radial system could have a similarly significant impact to
the BES depending on its location in the system.
Now consider the same system, but because of conditions within what was previously considered an LN (for example, non‐
BES generation dispatch and shifting load), the power now flows through the lower voltage system (Figure A3‐3).
Figure A3‐3: Bulk Electric System Flow through Local Network
In this case, the lower voltage system is not an LN since it is supporting flow through to the BES.
The 300 MW bright line is further supported by the following operational considerations:
1. Primary frequency response initially will be provided by the responding generating units in an interconnection. The
industry‐approved draft of the BAL‐003‐1 standard proposes that at least 1,700 MW of support will be provided
within the smallest interconnection by primary frequency response controls.37 This provides 5.7 times the resource
margin needed to stabilize an interconnection for a 300 MW loss or gain in LN load. The interconnections recover
from losses of generation in this MW range on a regular basis.
2. The requirements of the existing BAL‐002‐1 Disturbance Control Standard. Requirement R3 of the standard states,
“[a]s a minimum, the Balancing Authority or Reserve Sharing Group (RSG) shall carry at least enough Contingency
Reserve to cover the most severe single contingency.” Requirement R4.2 states that recovery shall occur within 15
minutes of the start of a Reportable Disturbance.38 Since the most severe single contingency in a Balancing
Authority or RSG is typically a nuclear generating unit, the requirements of BAL‐002‐1 would provide from 2.5 to 3
times the resource margin needed to support a 300 MW LN.39,40 This is supported by the fact that 89% of Balancing
Authorities are part of an RSG. All RSGs were identified as carrying a minimum Contingency Reserve of 750 MW,
which provides the resource margin stated above. Seven of the eight remaining Balancing Authorities that have
37
NERC Website (2012, October 30). BAL‐003‐1 Attachment A. Retrieved from
http://www.nerc.com/docs/standards/sar/Attachment_A_Frequency_Response_Standard_Supporting_Document_Clean_rev1.pdf
38
A Reportable Disturbance is an event that causes an ACE change greater than or equal to 80% of the most severe single contingency of
a Balancing Authority or RSG.
39
The available resource margin was based on the average net electrical output of a nuclear generating unit, which was calculated to be
980 MW from the reactor data posted on the U.S. Nuclear Regulatory Commission Website (9/14/2012). List of Power Reactor Units.
Retrieved from http://www.nrc.gov/reactors/operating/list‐power‐reactor‐units.html.
40
Resource margin was calculated by dividing the contingency reserve used to meet the most severe single contingency (980 MW‐net) by
the proposed LN limit of 300 MW. This margin differs from a planning reserve margin.
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Appendix 3: Operational Considerations to Support Load Limit on Local Networks
load and do not participate in an RSG carry over 300 MW of Contingency Reserves and would also be supported by
surrounding entities as required by TOP‐004‐2, Requirement R6. The surrounding entities’ AGC systems would also
help balance real and reactive power needs. The eighth entity has 100 MW of load and a contingency reserve of at
least 220 MW; no real and reactive power balancing issues are anticipated for this entity.
3.
The ability of a Balancing Authority or Reserve Sharing Group to adjust real power resources to account for a 300
MW loss or gain in load. The 2012 estimated peak demands of Balancing Authorities average between 6,000 MW
and 10,000 MW.41,42 Therefore, a 300 MW LN represents approximately 3% to 5% of the average estimated peak
demand of a Balancing Authority. Since the generating resources that supply the demand are able to adjust power
output by ±2% per minute on AGC, a 300 MW loss or gain in LN load could be mitigated within the 15‐minute
recovery period allowed for a disturbance.43,44
Given the balancing capabilities identified in points 1 and 2 above and the fact that LNs are not intended for bulk power
transfer, their disconnection from the BES should not affect reliability when limited to 300 MW.
Since LNs are not intended for bulk power transfer, their disconnection from the BES should not affect reliability when
limited to 300 MW, given the balancing capabilities identified in points 1 and 2 above.
NOTE: The TPL transmission system planning standards require that projected customer demands and projected Firm
(non‐recallable reserved) Transmission Services are supplied at all demand levels (as applicable). The proposed
standard TPL‐001‐2 further clarifies that system peak and off‐peak load be modeled in the Near‐Term Transmission
Planning Horizon. Therefore, firm loads cannot be excluded from the planning process even if they are located within
an LN.
41
Based on whether the estimated peak demands (MW) of the largest ISOs/RTOs are included.
Estimated peak demand (MW) data obtained from NERC Website (2012). 2012 CPS2 Blounds. Retrieved from
http://www.nerc.com/docs/oc/rs/2012%20CPS2%20Bounds%20Report%20Final(Update20120821).pdf
43
Kirby, Brendan & Hirst, Eric (1996, December 16). Generator response to intrahour load fluctuations. IEEE Transactions on Power
Systems, 13(4), 1373‐1378. Retrieved from http://www.consultkirby.com/files/PE627.pdf
44
The paper referenced in footnote 7 states that hydro units can respond at 50% to 100% of their output per minute, combustion
turbines at 10% to 20% of their output per minute, and coal powered units at 1% to 3% of their output per minute. The above
information regarding thermal and hydro generating units is also supported by the following book: Kundur, P. (1994). Control of Active
Power and Reactive Power, Power system stability and control (p. 618). New York, NY: McGraw‐Hill, Inc.
An entity with 9,000 MW of generation is considered in this paper (the entity is within the average demand range of the Balancing
Authorities considered herein).
42
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BES Radial Exclusion
Low Voltage Level Criteria
Jonathan Sykes
Pacific Gas and Electric Co.
BES Definition SDT
SLC
May 23, 2013
Problem Statement
To satisfy FERC Order 773-A, additional
factors beyond impedance must be
considered to demonstrate that looped or
networked connections operating below 100
kV should not be considered in the
evaluation of Exclusion E1.
2
FERC Order 773/773a
FERC Order 773-A
Page 20, Paragraph 28...In the Final Rule, the Commission held that
radial systems with elements operating at 100 kV or higher in a
configuration that emanate from two or more points of connection
cannot be deemed "radial" if the configuration remains contiguous
through elements that are operated below 100 kV.
FERC Order 773
Page 95, Footnote 139…this footnote provides some parameters for the
SDT to consider as a technical justification to include some low voltage
loops (typical of distribution feeders) under the E1 exclusion:
- Voltage
- Impedance
- Proximity
- Length of Conductor
- Interconnected Transmission System
3
Procedure
3 Step Process
Review the regional voltage levels that are monitored on
major interfaces, paths, and monitored elements in the
operation of the various interconnections
Study the physics of the loop flows through the low voltage
loops (typical for distribution feeders) and determine various
situations from worst case to practical situations
Review design considerations that the industry uses to
prevent loop flow through low voltage loops
4
1 - Regional Criteria
WECC
Minimum Voltage Levels
Paths, SOLs, modeling
Eastern
Interconnection Voltage Levels
Defined Interfaces, SOLs, IROLs, modeling
ERCOT
Monitored Elements, SOLs, IROLs, modeling
Sub-transmission
Voltage Levels
5
2 – Loop Flow
Study the physics of low voltage loop flow
Worst case scenarios
Loop flow across low side bus
Loop flow across low side lines
% of high side flow transferred to low side for N-1
Low voltage loop flow based on typical conductor ratings.
6
2 – Loop Flow
Parametric study
7
3 – Design Considerations
Owners and operators design to prevent low voltage
loop flow
Protection and control schemes
Interlocking schemes/reverse power
Supply continuity considerations
8
Voltage Considerations
55 kV
44 kV
34.5 kV
22 kV
12 kV
4 kV
Chose 30 kV as a bright-line
based on initial discussions by sub-team; more
discussion and analysis is needed.
9
E-mail completed form to:
[email protected]
Standards Authorization Request
Form
Title of Proposed Standard
definition
NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System
Request Date
December 2, 2011
SAR Type
SAR Requester Information
(Check all that apply)
Name: Project 2010-17 Definition of Bulk Electric
System (BES) SDT
Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT Chair
Telephone: (813) 207-7994
Fax: (813) 289-5646
E-mail: [email protected]
New Standard
X
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?)
This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Purpose or Goal (How does this request propose to address the problem described above?)
Research possible revisions to the definition of BES (Phase 2) to address the issues identified through
Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition encompasses all
Elements necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
Standards Authorization Request
SAR Information
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and
technically sound definition of the Bulk Electric System (BES).
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?)
Revise the BES definition to identify the appropriate electrical components necessary for the reliable
operation of the interconnected transmission network.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Collect and analyze information needed to support revisions to the definition of Bulk Electric System
(BES) developed in Phase 1 of this project to provide a technically justifiable definition that identifies
the appropriate electrical components necessary for the reliable operation of the interconnected
transmission network. The definition development may include other improvements to the definition
as deemed appropriate by the drafting team, with the consensus of stakeholders, consistent with
establishing a high quality and technically sound definition of the BES.
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.)
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.
•
•
•
•
Form
Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources necessary for the reliable operation of the Bulk Electric System (BES)
The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous
BES - Determine if there is a need to change this position
Determine if there is a technical justification to revise the current 100 kV bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
2
Standards Authorization Request
SAR Information
network under certain conditions and if so, what the maximum allowable flow and duration
should be
Provide improved clarity to the following:
•
•
•
The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources
•
The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution
Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the BES.
Based on the potential revisions to the definition of the BES and an analysis of the application of, and
the results from, the exception process, the drafting team will review and if necessary propose
revisions to the ‘Technical Principles’ associated with the Rules of Procedure Exception Process to
ensure consistency in the application of the definition and the exception process.
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
This section is not applicable as the SAR is for a definition which is about Elements, Applicability of
entities is covered in Section 4 of each Reliability Standard.
Form
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.
3
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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.
Administers the transmission tariff and provides transmission
Transmission
services under applicable transmission service agreements (e.g., the
Service Provider
pro forma tariff).
Form
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
4
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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 box for all that apply.)
X
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.
X
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.
X
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.
X
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
X
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
X
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
X
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
X
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Form
5
Standards Authorization Request
Applicable Reliability Principles (Check box for all that apply.)
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Form
Explanation
6
Standards Authorization Request
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Form
7
Standards Authorization Request Form
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:
NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System
definition (This is a supplement to the original SAR for this project which
was approved by the Standards Committee on April 12, 2012.)
Date Submitted:
January 16, 2013
SAR Requester Information
Name:
Peter Heidrich
Organization:
FRCC and Chair of the Definition of Bulk Electric System Standards Drafting Team
Telephone:
1.813.207.7994
E-mail:
[email protected]
SAR Type (Check as many as applicable)
New Standard
X
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
Address the directives in FERC Order 773 issued December 20, 2012.
Purpose or Goal (How does this request propose to address the problem described above?):
Address the directives in FERC Order 773 issued December 20, 2012.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
Address the directives in FERC Order 773 issued December 20, 2012.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Address the directives in FERC Order 773 issued December 20, 2012.
Standards Authorization Request Form
SAR Information
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.)
Address the directives in FERC Order 773 issued December 20, 2012.
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
This section is not applicable as the SAR is for a definition which is about Elements. Applicability of
entities is covered in Section 4 of each Reliability Standard.
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
Administers the transmission tariff and provides transmission services
Revised (11/28/2011)
2
Standards Authorization Request Form
Reliability Functions
Provider
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
X
X
X
X
X
X
X
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.
Revised (11/28/2011)
3
Standards Authorization Request Form
Reliability and Market Interface Principles
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
X
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Y
Y
Y
Y
Related Standards
Standard No.
N/A
Explanation
N/A
Related SARs
SAR ID
Project 2010-17: NERC Glossary of
Terms - Phase 2: Revision of the Bulk
Electric System definition
Explanation
This is the original SAR for the BES definition project – Phase
2. This SAR is a supplement to the original SAR.
Regional Variances
Region
Explanation
ERCOT
N/A
FRCC
N/A
Revised (11/28/2011)
4
Standards Authorization Request Form
Regional Variances
MRO
N/A
NPCC
N/A
RFC
N/A
SERC
N/A
SPP
N/A
WECC
N/A
Revised (11/28/2011)
5
Standards Announcement
Project 2010-17 Definition of the Bulk Electric System
Phase 2 | Draft 1
Formal Comment Period: May 29, 2013 – July 12, 2013
Ballot Pool Forming Now: May 29, 2013 – June 27, 2013
Upcoming – Initial Ballot: July 3-12, 2013
Now Available
A formal comment period for Phase 2 of the Definition of the Bulk Electric System (DBES) is open
through 8 p.m. Eastern on Friday, July 12, 2013. A ballot pool is being formed and the ballot pool
window is open through 8 a.m. Eastern on Thursday, June 27, 2013 (please note that ballot pools close
at 8 a.m. Eastern and mark your calendar accordingly).
Special note concerning Phase 1 DBES implementation and relationship to Phase 2: Although NERC is
prepared to implement the Phase 1 definition on July 1, 2013 as planned, on May 23, 2013 NERC filed a
Motion For an Extension Of Time, asking FERC to grant an extension of the effective date of the Phase 1
definition of Bulk Electric System, from July 1, 2013 to July 1, 2014, in order to alleviate regulatory
uncertainty. If the extension is granted, the implementation plan for Phase 1 would also be extended
based on the extension of the effective date. FERC approved the Phase 1 definition of BES in Order No.
773, but also directed changes. These changes, along with work previously assigned to the drafting
team for Phase 2, are being implemented through the standards development process during Phase 2
of this project.
Background information for this project can be found on the project page.
Instructions for Joining Ballot Pool(s)
Registered Ballot Body members must join the ballot pool to be eligible to vote in the balloting of the
DBES - Phase 2. Registered Ballot Body members may join the ballot pool at the following page: Join
Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from
using the ballot pool list server.)
The ballot pool list server for this ballot pool is: bp-2013 Project [email protected]
The ballot pool is open through 8 a.m. Eastern on Thursday, June 27, 2013.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, July 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 form is posted on the project
page.
Next Steps
An initial ballot will be conducted July 3, 2013 through 8 p.m. ET Friday, July 12, 2013.
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 2010-17 DBES Phase 2
2
Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Phase 2 | Draft 1
Ballot now open through 8 p.m. Eastern July 12, 2013
Now Available
A ballot for Phase 2 of the Definition of Bulk Electric System (DBES) is open through 8 p.m. Eastern on
Friday, July 12, 2013.
Special note concerning Phase 1 DBES implementation and relationship to Phase 2: Although NERC
was prepared to implement the Phase 1 definition on July 1, 2013 as planned, on May 23, 2013 NERC
filed a Motion For an Extension Of Time, asking FERC to grant an extension of the effective date of the
Phase 1 definition of Bulk Electric System, from July 1, 2013 to July 1, 2014, in order to alleviate
regulatory uncertainty. On June 13, 2013, FERC issued an order granting the requested extension. In
the order, FERC provided the following information:
…the Commission expects NERC to file the changes to comply with the Order Nos. 773 and 773-A
directives in sufficient time to allow the Commission to process NERC’s proposal in response to the
directives well in advance of the July 1, 2014 effective date. Therefore, NERC should submit a filing that
includes proposed modifications to comply with the directives pertaining to exclusions E1 and E3 as soon
as possible prior to December 31, 2013. Any delay in the submission of a filing that addresses the
responsive modifications could impede the Commission’s ability to act on the directives prior to July 1,
2014. The Commission does not anticipate granting any further extensions of the effective date beyond
July 1, 2014.
Background information for this project can be found on the project page.
Instructions
Members of the ballot pool associated with this project may log in and submit their vote for the
definition by clicking here.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will
consider all comments received during the formal comment period and, if needed, make revisions
to the definition. If the comments do not show the need for significant revisions, the definition 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
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2010-17 DBES Phase 2
2
Individual or group. (94 Responses)
Name (64 Responses)
Organization (64 Responses)
Group Name (30 Responses)
Lead Contact (30 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (24 Responses)
Comments (94 Responses)
Question 1 (55 Responses)
Question 1 Comments (70 Responses)
Question 2 (54 Responses)
Question 2 Comments (70 Responses)
Question 3 (58 Responses)
Question 3 Comments (70 Responses)
Question 4 (54 Responses)
Question 4 Comments (70 Responses)
Question 5 (50 Responses)
Question 5 Comments (70 Responses)
Question 6 (61 Responses)
Question 6 Comments (70 Responses)
Group
Florida Municipal Power Agency
Frank Gaffney
Agree
We support TAPS comments
Individual
ddd
ddd
Agree
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Yes
No
AECI suggests the SDT consider the following change for I2: REPLACE: “Generating resource(s)
and dispersed power producing resources,” WITH: “Generating resource(s) and dispersed
power producing resources connected at 100 kV and above,” RATIONALE: Clarity of intent.
Inclusion I2’s order and new separation of wording, appears to make “the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above” stand autonomous.
Because “step-up transformer” is not defined in the NERC Glossary, AECI is deeply concerned
that the current wording can become twisted to instruct industry to first locate their Plants
greater than 75 MVA and Units greater than 20 MVA, next locate all the transformers
connecting them to the core BES at a voltage of 100 kV or above, and finally include all the
wires "between," which is most all of the sub-transmission systems and including sub-subtransmission following FERC's most recent logic. The core BES definition’s “Unless modified by
the lists shown below”, will further support this reading and go against what the BES Phase II
SDT has been assuring industry, that primarily elements 100 kV and above are part of the BES.
AECI expresses this further concern for SDT consideration: With E3 now excluding I2, it
appears to be in technical conflict with E2, where E3 for a potential LN but with any interior
unit greater than 20 MW yet continuously consuming All interior generation and more (per
E3b), cannot be excluded and yet E2 can. Why?
Yes
AECI appreciates the SDT's establishing a kV floor and yet feels that a 70kV floor could
accommodate FERC's concerns, with minor additions to establish some threshold for obvious
sub-network transfer-limitations between sub-network transformer terminals.
No
The SDT needs to clarify "generator terminals" due to this current definition's potential
inclusion all the way down to individual PV cell's solder-pads and battery's terminals. (These
technically are the first electrical access-points for where conversion takes place from other
energies to electrical energy.) From a BES Reliability aspect, the worst-case contingency is
total loss of the resource at its greatest aggregated entry point to the BES. Therefore AECI
recommends that the SDT revert to their earlier wording. Technically, loss increments below
that worst-case level, and especially for weather-sensitive solar and wind, seem no different
to System Operators than derations on any large coal-fired Units. On the other hand, if the
SDT's intent is to draft Standards in a manner to disincent renewable energy producers from
aggregating their resources to the grid in excess of 75 MVA, then perhaps the SDT is providing
the proper forcing-function here. If so, they should show equal concern for any other type of
new generating units that are sized in excess of the same 75 MVA threshold.
Yes
Yes
AECI recommends for E3c: REPLACE: "Flowgate", WITH: "reliability type Flowgate",
RATIONALE: The Eastern Interconnection's Book of Flowgates contains both "(Informational)"
and "(Reliability)" types of Flowgates. Line-item example excerpts: "/ Type: PTDF
(Informational)" -versus- "/ Type: PTDF (Reliability)". AECI believes only elements from the
reliability type FGs could be of concern here.
Group
Northeast Power Coordinating Council
Guy Zito
No
The Directive was addressed by the revision, but generally Exclusion E3 does not recognize
that regardless of how power gets to the load, it impacts the Bulk Electric System. The term
bulk power is used in the opening sentence of E3. A definition of bulk power would lend
credence and justification to E3, and the elimination of “or above 100 kV but”. The new Note
2 associated with Exclusion E1 and the changes to E3 have added ambiguity that did not exist
before. The base definition does not address sub 100kV contiguous loops. The existing
Inclusions do not include sub 100kV contiguous loops either. Note 2 clarifies that as long as
the contiguous loop is below 30kV E1 still applies. E3 explains how any sub 300kV contiguous
loop could be excluded as a local area network, but there is nothing in the definition that
clearly states that contiguous loops operated below 100kV are considered part of the BES
unless excluded by E3. The 100kv threshold has been removed from the first sentence of E3,
but it is inconsistent that the 100kV reference remains in the second part of the E3 exclusion.
It is unclear what value the second sentence of the E3 exclusion provides, and its removal
should be considered. Under the premise that the very first paragraph of the BES Definition
already establishes the bottom voltage threshold of 100kv, we agree with removing the
mention of the 100kV bottom threshold in exclusion E3. The version of exclusion E3 criterion
(c) filed with FERC January 25, 2012 (RM12-6-000) requires a “Local Network” not to contain a
monitored facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored facility in the ERCOT or
Quebec Interconnections, and is not a monitored facility included in an Interconnection
Reliability Operating Limit (IROL). The definition became more vague by changing exclusion E3
criterion (c) from “a monitored Facility of a permanent Flowgate…” to “any part of a
permanent Flowgate…” and could allow for too broad a reading. The original language from
Phase 1 of the BES definition regarding exclusion E3 criterion (c) provided more clarity and
guidance on how to apply this exclusion. It is recommended that the original language from
Phase 1 of the BES definition be reinstated. Facilities should be included in the BES only if the
elements of the Facility are transferring power (flow) through a Flowgate, transfer path, or
IROL. The Phase 1 BES definition was approved by NERC after positive industry acceptance
providing that Phase 2 would reconsider some of the thresholds proposed in Phase 1. The
important 75MVA generation threshold limit was included. The FERC requested changes now
limit the possibilities for exclusion: 1) limitation on the possibility of radial exclusion because
of looping below 100 kV; 2) refusal of radial or local exclusions when there is at least one
generator above 20 MVA. Those limitations for exclusion go in the opposite direction to what
industry expected. NERC must realize that the definition will be applied to entities not under
FERC jurisdiction. It is important that NERC consult Canadian jurisdictions about the BES
definition.
No
I2 does not include “non-retail” generation which is inconsistent with E1 and E3. E1b, c, and
E3a contain redundant statements regarding the 75MVA generator threshold. These
statements should be corrected for clarity and consistency. For Simple E1 Radial System
Exclusions--The Drafting Team application of this FERC directive is clear for simple E1 Radial
System Exclusions. Any tie-line connected radially to the BES and operated at 100kV or above
connecting I2 or I3 generation (aggregating to more than 75MVA) is part of the BES. However,
beyond this simple configuration the application of the tie-line directive is less clear. For the
More Complex E1 Radial System Exclusions--More complex applications of the tie-line
directive under the proposed BES Definition are less clear. Consider that Inclusion I2 states
the tie-line includes “… the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above...” It could be argued that this was
intended to apply to a short line or bus connection between the generator and the generator
step-up unit. But in reality it could be a long connection. Regardless, a fault can occur on any
length of line or bus. Application of the tie-line directive is less clear when there are multiple
feeders and transformations between the generating resource and the BES which include sub100kV operating voltages. For example, a GT with a 13.8kV output feeds local distribution.
This local distribution is also served by a 69-to-13.8kV step-down transformer that is fed by a
69kV sub-transmission feeder supplied by a 138-to-69kV transformer connected to the BES by
a 138kV feeder serving multiple step-down transformers to load. This Radial System has only
one connection to the BES at 138kV. What facilities are covered by the tie-line directive,
either the entire path from “… the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” or only the portion of the 138kV
feeder from the high-side terminals of the 138-to-69kV step-down transformer to the BES?
For the E3 Local Network Exclusion--Applying the tie-line directive within a Local Network
could be problematic. The proposed wording introduces issues similar to those involving
Cranking Paths from Black Start units. Local Networks by the definition “emanate from
multiple points of connection at 100 kV or higher.” Defining a single tie-line through the Local
Network presents problems. Is the tie-line the shortest path geographically or electrically?
Does the tie-line directive suggest single or multiple paths to the BES? The CIP drafting team
recognized this problem and defined the path, eliminating Regional or Entity discretion and
avoiding substantial ambiguity and confusion. Following the CIP Drafting Team example,
suggest adding the following wording: Note 3: The BES tie-line is defined as the portion of the
single shortest contiguous path operated at 100kV or above from the I2 or I3 resource to the
BES. The Radial System or Local Network excluded must be defined so that it does not include
a BES tie-line. Portions of the tie-line path operated below 100kV are not part of the BES.
Application of this note does not extend to tie-line facilities operated below the 100kV core
definition.
No
Exclusion E1 provides a floor (30 kV threshold) for which an entity does not have to consider
the loop in its determination of a radial system. Due to the international nature of the ERO,
consideration must be given to what the various Provinces consider to be “distribution level”,
and any proposed revision should recognize this dissimilarity. In addition, in the United States
various state representatives have cited jurisdictional issues associated with lowering the
threshold to 30 kV. This also impacts the 100 kV bright‐line threshold definition. The 30kV
threshold as currently written is too restrictive. In a similar way as 100 kV is the delineator
between the medium and high system voltage classes in the American National Standards
Institute (ANSI) standard on voltage ratings (C84.1), the voltage threshold in note 2 of
exclusion E1 should be based on well defined standard system voltage classes to better
correlate to operational and system design considerations and practices. The Exception
Procedure could be used to include lower (than 100 kV; bright line) voltage systems in the BES
envelope when interactions between these systems and the BES are deemed critical to
reliable operations in their local or regional area. The demarcation point between
transmission and distribution may be different in non-FERC jurisdictions, such as the Canadian
Provinces. For example, in Ontario, legislation establishes 50kV as the technical boundary line
between transmission and distribution. In establishing voltage thresholds, NERC needs to
consider non-U.S. legislated demarcation points, and the standard development process must
make allowances for such regulatory and/or jurisdictional differences. The establishment of
the voltage floor for the E1 exclusion as currently written is inconsistent with the language
and structure of the legislative framework in Ontario. The Exception Process is not
appropriate to determine the jurisdictional issue of whether facilities are part of the Bulk
Electric System. Note 2 should be modified to read as follows: Note 2 – The presence of a
contiguous loop, operated at a voltage level below the applicable cut-off between
configurations being considered as radial systems, does not affect this exclusion. The
applicable cutoff is 30kV or less, unless deemed otherwise by regulatory authority. A technical
justification is not required where a Provincial jurisdictional finding is applicable.
No
It should be considered that dispersed generators that are represented to the marketplace or
modeled in study cases as 20MVA or higher should be included in the definition just as a
single traditional generating unit of 20 MVA is included. By removing I4, the aggregating
portion of the inclusion has been muddied. Suggest adding I2-c to include dispersed resources
that are aggregated and modeled at 20MVA or higher. This would add clarity and consistency
to the definition. The impact of the proposed response to Commission directives (and the
directives themselves) in effect bring wind generation collector systems and any other
aggregation system for other resource technologies into the definition of Bulk Electric System.
Recommend that there be an exclusion for wind generation collector systems which are radial
in nature and do not serve any retail load provided adequate protection for the BES via
protective systems installed at the point of interconnection. Bringing many thousands of 1-2
MW generators directly into the reliability regime of the ERO is not necessary, or justified. In
plants with an aggregate rating greater than 75 MVA, the individual generators should be
treated in the same manner as if they were each a stand-alone facility. If the individual
generator is at or below 20 MVA in a stand-alone facility it would not be included in the BES
and the owner of such a facility would not even have to register as a generator owner. That
same size generator in an aggregated facility should be treated the same and it should be
excluded from the BES. The portion of the facility at which the 75MVA or greater aggregation
occurs should be where the BES boundary should be occurring. To demonstrate the concept,
an illustration marked as Figure 1 has been submitted to Monica Benson (NERC). From FERC
Order 733A beginning at paragraph 50, “we direct NERC to modify the exclusions pursuant to
FPA section 215(d)(5) to ensure that generator interconnection facilities at or above 100 kV
connected to bulk electric system generators identified in inclusion I2 are not excluded from
the bulk electric system”. To that end, I2 should be revised to read: I2 - Generating resource(s)
and dispersed power producing resources, including their power delivering assets operated at
a voltage of 100 kV or above with:
No
For Exclusion E4 Reactive Devices - The drafting team agreed that use, and not ownership,
should dictate the disposition of reactive devices. Reactive devices used to support retail
customer loads, and not used in day-to-day operations for BES voltage control for either
steady state or contingency operations, may be excluded from the BES regardless of
ownership. Devices need not be owned by “a retail customer” as a prerequisite for exclusion.
Reactive devices owned by others, such as a Transmission Owner, and installed solely for the
benefit of retail customer load should also qualify for exclusion. The proposed wording still
carries remnants of the previous retail customer concept. It refers to a singular customer. Yet,
reactive devices may be installed to benefit a group of retail customers collectively referred to
as retail load. Suggest revising E4 to either read: E4--Reactive Power devices installed for the
sole benefit of retail customers. or E4--Reactive Power devices installed for the sole benefit of
retail load.
Yes
The specifics of system configurations and applications in the Inclusions and Exclusions should
be reviewed to be made less complex. If they are not simplified they can be expected to
generate a large number of requests for exclusion consuming resources in regional processing
and at the ERO. As an alternative, an updated, conforming Guidance Document clarifying the
intent and containing explicit explanations and one-line diagram examples should be
provided. The version previously posted does not conform to the Phase 2 changes proposed.
Phase 2 of the BES definition process was supposed to address the 100kV threshold, the
generator thresholds and the reactive resource thresholds for inclusion or exclusion. No
formal studies have shown that these numbers are the correct numbers for this definition.
The studies provided under Phase 2 had no more technical justification than those discussions
by the Standard Drafting Team in Phase 1. Being able to have that technical justification
provides the support necessary to maintain a reliable transmission system and provides a
basis for analysis of reliability by industry participants. Based on FERC orders 773 and 773-A
and NERC’s response to those orders, the value of Note 1 under E1 has been diminished and
suggest it be removed. It must be considered that industry has typically considered the terms
‘network’ and ‘contiguous’ to exclude elements or facilities that contain a normally open
device (switch, breaker, disconnect, etc.) between them. 1) NERC must consider that any new
or changes to standards as a result of FERC directives that apply to load reliability and load
supply continuity are limited to the FERC jurisdiction only. For example, in Canada, local load
reliability requirements are under the authority of local regulators such as the OEB in Ontario.
2) The Implementation Plan does not conflict with the Ontario regulatory practice with
respect to the effective date of the standard. It is suggested that this conflict be removed by
appending to the effective date wording, after “applicable regulatory approval” in the
Effective Dates Section of the Implementation Plan, the following: “, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.” The same
changes should be made to the first sentence in the Effective Date Section on page 2 of the
Definition document. The main concern about the Phase 2 definition is that it reduces more
than the Phase 1 definition by the possibility of exclusions, and that no proper technical
analysis had been given to justify or reduce the proposed threshold. FERC's request should
not force obligations on non-United States jurisdictions. NERC must consult with and treat
both United States and non-United States jurisdictions equally.
Individual
Tracy Richardson
Spirngfield Utility Board
Agree
American Public Power Association.
Group
Arizona Public Service Company
Janet Smith, Regulatory Compliance Supervisor
Yes
Yes
Yes
Yes
Yes
Yes
I5 is still problematic. It only excludes reactive resources which are excluded by E4. We
suggest following: “unless excluded by exclusion of E1 to E4”. For example there is no
justification to include reactive resources connected to a radial system as part of BES which
are there to serve the radial system. Since the radial system is not part of BES, why include
the reactive resources connected to radial system as part of BES.
Group
Northeast Utilities
Tim Reyher
No
While it is recognized that electrical systems operated below 100KV can be configured such
that they should require BES treatment (i.e. the 92 KV networked system involved in the 2011
Southern California – Arizona outage), a 30KV threshold is too low to significantly impact the
reliable operation of the higher voltage transmission system. We propose increasing this
threshold to a voltage in the 40-50KV range. The new Note 2 associated with Exclusion E1 and
the changes to E3 have added ambiguity that did not exist before. The base definition does
not address sub-100kV contiguous loops. The existing Inclusions do not include sub 100kV
contiguous loops either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1
still applies. E3 explains how any sub 30kV contiguous loop could be excluded as a local area
network, but there is nothing in the definition to clearly state that contiguous loops operated
below 100kV are considered part of the BES unless excluded by E3. An additional Inclusion
should be added that specifically includes “all contiguous loop operated below 100kV that is
not solely used for the distribute power to load unless excluded by application of Exclusion E1
or E3.” The proposed change to the E1 exclusion definition to add Note 2 will require an
examination of NU sub-transmission system connections (69KV in CT and 34KV in NH) and
their connections to the >100KV transmission systems. Elements >100KV originally
categorized as E1 or E3 may become BES inclusions if there is underlying sub-transmission
path. A cursory review determine no elements categorized as E1 in CT would be changed;
however, 16 of the 30 E1 elements in NH could become BES due to 34KV paths.
While it is recognized that electrical systems operated below 100KV can be configured such
that they should require BES treatment (i.e. the 92 KV networked system involved in the 2011
Southern California – Arizona outage), a 30KV threshold is too low to significantly impact the
reliable operation of the higher voltage transmission system. We propose increasing this
threshold to a voltage in the 40-50KV range. The new Note 2 associated with Exclusion E1 and
the changes to E3 have added ambiguity that did not exist before. The base definition does
not address sub-100kV contiguous loops. The existing Inclusions do not include sub 100kV
contiguous loops either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1
still applies. E3 explains how any sub 30kV contiguous loop could be excluded as a local area
network, but there is nothing in the definition to clearly state that contiguous loops operated
below 100kV are considered part of the BES unless excluded by E3. An additional Inclusion
should be added that specifically includes “all contiguous loop operated below 100kV that is
not solely used for the distribute power to load unless excluded by application of Exclusion E1
or E3.” The proposed change to the E1 exclusion definition to add Note 2 will require an
examination of NU sub-transmission system connections (69KV in CT and 34KV in NH) and
their connections to the >100KV transmission systems. Elements >100KV originally
categorized as E1 or E3 may become BES inclusions if there is underlying sub-transmission
path. A cursory review determine no elements categorized as E1 in CT would be changed;
however, 16 of the 30 E1 elements in NH could become BES due to 34KV paths.
Yes
While it is recognized that electrical systems operated below 100KV can be configured such
that they should require BES treatment (i.e. the 92 KV networked system involved in the 2011
Southern California – Arizona outage), a 30KV threshold is too low to significantly impact the
reliable operation of the higher voltage transmission system. We propose increasing this
threshold to a voltage in the 40-50KV range. The new Note 2 associated with Exclusion E1 and
the changes to E3 have added ambiguity that did not exist before. The base definition does
not address sub-100kV contiguous loops. The existing Inclusions do not include sub 100kV
contiguous loops either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1
still applies. E3 explains how any sub 30kV contiguous loop could be excluded as a local area
network, but there is nothing in the definition to clearly state that contiguous loops operated
below 100kV are considered part of the BES unless excluded by E3. An additional Inclusion
should be added that specifically includes “all contiguous loop operated below 100kV that is
not solely used for the distribute power to load unless excluded by application of Exclusion E1
or E3.” The proposed change to the E1 exclusion definition to add Note 2 will require an
examination of NU sub-transmission system connections (69KV in CT and 34KV in NH) and
their connections to the >100KV transmission systems. Elements >100KV originally
categorized as E1 or E3 may become BES inclusions if there is underlying sub-transmission
path. A cursory review determine no elements categorized as E1 in CT would be changed;
however, 16 of the 30 E1 elements in NH could become BES due to 34KV paths.
Individual
Dennis Schmidt
City of Anaheim
No
This Question No. 2 has clearer language than the Exclusions E1 and E3 themselves when it
qualifies the interconnected generation as “BES generation.” As discussed below, Exclusions
E1 and E3 should be modified to make clear that non-BES generation (i.e., any non-Inclusion
I2/I3 generation that is connected to non-BES facilities, including distribution facilities
operated below 100 kV) does not disqualify a registered entity from either Exclusion E1 or
Exclusion E3. Exclusions E1 and E3 should clearly state that the 75 MVA limitation on
generation resources contained in Exclusions E1(c) for radial systems and E3(a) for local
networks applies to generation resources that are actually connected to the potentially
excluded radial system or local network. The 75 MVA limitation should not apply to non-BES
generation that may be connected to a sub-100 kV distribution system beyond the radial
system or local network. Anaheim believes that the Drafting Team may intend for the existing
(i.e., Phase 1) definition to be applied in this manner. For example, both the radial system and
local network definitions refer to “contiguous transmission Elements,” which do not include
“distribution Elements.” A 75 MVA (or greater) generator connected to a 69 kV local
distribution Element is not contiguous to the BES, nor is it connected to a transmission
Element; therefore, such distribution system generation should not preclude the radial
system or local network from being excluded from the BES. Anaheim’s proposed revisions to
Exclusions E1 and E3 to address this issue are provided below. To the extent that the Drafting
Team already intends for the existing (i.e., Phase 1) BES definition to be interpreted and
applied as described in these comments and that no further changes to the Exclusions are
warranted, then Anaheim requests that the Drafting Team confirm this in future guidance
documents or that the Drafting Team so specify in response to these comments. Exclusion E1:
E1 – Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and: a) Only serves Load. b) Only includes
generation resources, not identified in Inclusion I2 or I3, with an aggregate capacity less than
or equal to 75 MVA (gross nameplate rating). c) Where the radial system both serves Load
and includes generation resources, the generation resources (i) are not identified in Inclusions
I2 or I3 and (ii) have an aggregate capacity of non-retail generation less than or equal to 75
MVA (gross nameplate rating) directly connected to the radial system. [Anaheim proposes no
changes to the remainder of Exclusion E1; for brevity, the remainder of this exclusion has not
been restated.] Exclusion E3: E3 – Local networks (LN): A group of contiguous transmission
Elements operated at less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LNs emanate from multiple points of connection at
100 kV or higher to improve the level of service to retail customs and not to accommodate
bulk power transfer across the interconnected system. The LN is characterized by all of the
following: a) Limits on connected generation: The LN does not include generation resources
identified in Inclusions I2 or I3 and does not have an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating) directly connected to the LN at a
voltage of 100 kV or above; [Anaheim proposes no changes to the remainder of Exclusion E3;
for brevity, the remainder of this exclusion has not been restated.]
Yes
For clarity, a minor grammatical change should be incorporated into Inclusion I2. Specifically,
a comma should be placed after the word “transformer(s)” and before the phrase “connected
at a voltage of 100 kV or above.” Thus, Inclusion I2, as revised, should state: Inclusion I2 –
Generating resource(s) and dispersed power producing resources, including the generator
terminals through the high side of the step-up transformer(s), connected at a voltage of 100
kV or above with: a) Gross individual nameplate rating greater than 20 MVA, or b) Gross
plant/facility aggregate nameplate rating greater than 75 MVA.
Group
Dominion
Louis Slade
Yes
However, please see our comments to remaining questions. .
Yes
No
Dominion believes that there should be some way to insure that the requirement does not
require exclusion be validated solely by use of powerflow. We therefore suggest the following
revision to E1 (a) Only serves Load. A normally open switching device between radial systems
may operate in a ‘make before break’ fashion to allow for reliable system reconfiguration to
maintain continuity of service and not require a powerflow model. We endorse the MRO
comment - "The NSRF believes the 30kV threshold is too low and the SDT justification is
inadequate. The BES operates at various kV classes. As power density and distance grow,
lower voltage classes are rendered ineffective at transporting bulk electric system power.
Therefore, certain voltage classes below 100 kV are clearly limited in their ability to transport
bulk electric power and should be ruled as distribution facilities under the 2005 FPA." We
endorse the MRO Comment - "MRO members have expertise in performing interconnected
system modeling & operational analysis which indicates that all three attributes comprising
the technical justification used by the SDT are always satisfied with the 60kV threshold. The
recommended 60kV threshold recognizes that 69kV is the lowest voltage at which loops
between radial systems have the potential to support adequate amount of power transfer
under certain worst case scenarios and thus may impact the >100kV system
performance/reliability. In other words, system modeling & operational analysis experience
indicates that 69kV is the lowest voltage at which loops between radial systems present any
possibility that any one of the three attributes in the SDT’s technical justification may not be
satisfied. "
Yes
Yes
Yes
Based on FERC orders 773 and 773-A and NERC’s response to those orders, Dominion no
longer sees the value of Note 1 under E1 and suggests it be removed. Further Dominion
believes the industry has typically considered the terms ‘network’ and ‘contiguous’ to exclude
elements or facilities that contain a normally open device (switch, breaker, disconnect, etc)
between them. Although Dominion initially thought it understood the meaning of the BES
definition, our attendance at seminars in June and the attempted application of the BES
definition to the Dominion system has led to some confusion. Please provide additional clarity
on the Local Network exclusion E3b. The BES definition is vague and ambiguous as to whether
flow out of the network requires study under N-0, N-1, N-2, etc. conditions. The SDT has
stated that one does not have to perform loadflow studies to determine a local network. It
has also stated in the guidance document that two years of historical flow data may be used
to make the determination. Both of these imply the BES is to be evaluated under an N-0
situation. On the other hand the SDT has stated “This definition, as approved, clearly specifies
no outward flow from the local network under any conditions and for any duration.”
{comments on guidance document October 4, 2012 through November 5, 2012}. This implies
that some type of contingency analysis must be performed. Consider as an example, Figure
E3‐3 of the April 2013 Guidance document. With all lines in service as depicted, the 138 kV
system is undoubtedly a local network. However, if the definition truly means “under any
condition” then one could select an a set of <300 kV and 138 kV contingencies that would
force power through the 138 kV and then back onto the BES since there is no alternate path.
This would negate the assertion that this is non-BES and excludable. We doubt if that is the
SDT intent and believe the definition as written is silent on the contingency issue. Clearly
there needs to be a practical limit to how many contingencies one would need to take or
clarificiation whether contingencies should be taken at all. Evaluation at all load levels, all
credible dispatches with a variety of contingencies is tremendously burdensome. Our
preference would be to evaluate with all lines in service (N-0) since this would insure
maximum buy-in from stakeholders. E3b should read : E3b) “Power flows only into the LN and
the LN does not transfer energy originating outside the LN for delivery through the LN under
normal (non-contingency) conditions…” The Guidance document, as revised for phase II, is
important to understand the BES definition. It introduces concepts not explicitly mentioned in
the BES definition (“The SDT’s intent was that hourly integrated power flow values over the
course of the most recent two‐year period would be sufficient to make such a
demonstration.”) However, the guidance document does not have legal standing since it is
not FERC approved. We think it should go through the interpretation process for stakeholder
review and be integrated into the BES definition with FERC approval.
Group
Cogeneration Association of California
Donald Brookhyser
Yes
There are several issues regarding industrial facilities that should be addressed in Phase 2.
Including the facilities of any individual industrial customer in the BES and making them
subject to NERC standards and enforcement unreasonably expands a program designed to
regulate utilities. This shifts the responsibility for utility functions to individual, nonjurisdictional entities, including industrial customers, and customer generators. It is ironic that
these entities built generation for increased reliability of service to their installations – not to
serve the grid - and in many cases to substitute for the less-than-reliable utility grid service.
The comments to FERC on the NOPR and in the requests for rehearing raised several issues
with regard to industrial facilities that FERC deferred to Phase 2. These comments include
those advocating exemption of industrial facilities with power flowing through and out to the
grid, such as those asserted by Dow and Valero. The issues associated with industrial
customers employing self-generation to serve on-site load should appropriately be included in
this Phase 2 effort. To address these issues, CAC, EPUC and CLECA propose four development
initiatives within Phase 2: • First, there should be an additional exclusion from the bright-line
test: •If the element is not owned or operated by a public utility regulated by a state authority
as a common carrier, or by FERC as a public utility, there is a presumption that the element is
not part of the Bulk Electric System (BES); • For any element that is not a public utility, and
that is asserted to be material to the reliability of the BES, the burden is on the regional entity
or the interconnected public utility to demonstrate that the non-public utility customer
facilities are an essential and material part of the BES. • This shift in burden is important
because of the difficulty for an individual industrial customer/self-generator to obtain the
necessary data to model its impact on grid reliability. Confidential modeling of power flows or
information of other customers’ usage is not going to be provided by the utilities to customer
generators as market participants. • Second, there should be a functional test specified for
determining “material impact” to grid reliability, to facilitate the exclusion of elements. FERC
in Order 743 and subsequent orders finds that a functional test of “no material impact” may
not be sufficient to identify elements that are “necessary to operate the system.” In footnote
35 of the April 18 rehearing order, FERC indicates that NERC has the option to develop such a
test. A test of “no material impact and unnecessary to operate the system” should be
developed, particularly to allow the exclusion of industrial facilities never intended to support
grid reliability. • Third, NERC should further analyze the issue of power flowing out of a local
network. Industrial facilities have often constructed two interconnections to the grid. This has
typically been done to ensure reliability of service to the end-use industrial facility, but in
doing so, it may also inadvertently provide a path for flows of small amounts of power
through the interconnection points back to the grid. The purpose of the dual interconnection
is reliability and not to provide transfers of energy across the bus. The transmission operator
is not likely to depend on the interconnection point as a means to provide grid service to
other customers or to model that service in its transmission planning studies. NERC’s technical
studies should provide FERC with some criteria for exempting industrial facilities with singlesourced dual feeds that are not intended to support the grid as a transfer path for power and
are not modeled as such by the Transmission Planner or Balancing Authority. • Fourth, NERC,
under the E-1 exclusions for radial lines, should not unilaterally dismiss the exclusion for radial
lines if the industrial customer has more than one line servicing its facility. Most large
manufacturing facilities are served by multiple feeds to maximize service reliability. This is
done because the load is more reliable than the lines serving the facility. A refinery, chemical
plant or other 24/7 facility cannot afford to operate without redundant power lines. Dual
feeds, typically from the same utility substation, are constructed to provide benefits to both
the utility and the large industrial customer. With that configuration the utility can maintain
its revenue stream while performing routine maintenance without shutting-in a facility. In the
case of a refinery, if it were forced to shut down during routine line maintenance, it can take
up to several days to safely shut down and even longer to start up. By having redundant lines,
often on the same poles, a facility can save millions of dollars in shut down costs and other
related expenses. It would be commercially negligent in many cases for large customers not
to have the redundancy. Utilities can provide increased reliability and perform repairs more
safely with the redundant lines. In no way does the fact that two lines providing service to a
single large industrial facility, typically from the same utility source, change the characteristic
of that service as being anything more than a radial line feed.
Individual
Steve Alexanderson
Central Lincoln
Yes
Central Lincoln agrees the SDT has addressed the directive, but continues to believe the
conditions on outflow and through flow are excessively restrictive. Please see further
comments in the response to Question 6.
Yes
Yes
Central Lincoln supports the approach, but questions the threshold. Central Lincoln protests
that the SDT plans to make its white paper on the technical analysis to justify the 30 kV
threshold available after the comment/ballot period is over. While a 5 kV shift would not
affect Central Lincoln, we are aware of entities that would be in favor of a 35 kV threshold
instead. Please give us the information needed to evaluate the SDT's choice of 30 kV.
Yes
Yes
Yes
1)Central Lincoln remains concerned regarding the limits imposed by b) on local networks. We
note that by order 773A, FERC considers this limit to be absolute with no allowance for
minimal reverse flows for even brief periods under multiple contingencies. While denying
rehearing on this issue, FERC specifically invited Phase 2 to adjust this outcome in paragraph
79 of the order. We also note that the BES Definition Reference would allow very brief flows
out of a local network as long as the integrated hourly flow was still into the local network.
FERC, however, did not rule on the Reference document, only the definition itself. Even if
FERC did allow the language of the Reference document, the first multiple contingency event
that results in out flow or through flow for the better part of an hour would cause an
excluded network to become immediately included, and subject to standards without any
implementation period (assuming 24 months had passed from the effective date of the
definition). The Planning Committee provided several options to SDT on this matter. We
understand the SDT’s reluctance to impose system studies on what is intended to be a simply
determined bright line criterion, but the present exclusion is not very useful. Central Lincoln
would support using a fixed two year (or longer) window rather than the most recent two
year sliding window suggested in the reference document. However it is determined, it should
be included within the approved definition so that the reference document disclaimer does
not apply. 2)Non-retail generation still lacks a definition to be approved by NERC and FERC,
even though this this item was specifically included in the approved SAR. We note that the
term is defined in the Reference Document where the disclaimer stating it is not an official
position of NERC ensures this definition has little value. While the Reference Document states
“Non‐retail generation is any generation that is not behind a retail customer’s meter,” we
continue to hear it defined without the “not.” It is very important that entities and regions
have a common understanding of the term, and ask the team to include its definition within
the BES definition.
Individual
Doug Hohlbaugh
FirstEnergy
Yes
Yes
Yes
FirstEnergy supports the proposed 30kV threshold for Exclusion E1 based on the explanation
provided in the June 26, 2013 industry webinar and information presented by the drafting
team in the supplemental material/presentation titled “BES Radial Exclusion Low Voltage
Level Criteria”.
Yes
Yes
No
Individual
PHAN, Si Truc
Hydro-Quebec TransEnergie
No
The phase 1 BES definition was approved by NERC after a positive acceptation by industry,
providing that phase 2 would reconsider some of the thresholds proposed in phase 1. Among
the thresholds, the limit of 75 MVA was an important one. Now, FERC request important
changes that limit the possibility of exclusion : 1) limitation on the possibility of radial
exclusion because of looping below 100 kV; 2) refusal of radial or local exclusions when there
are at least one generator above 20 MVA. Those limitations for exclusion go in the opposite
direction to what industry expected. In that sense, HQT (Hydro-Québec-TransÉnergie) doesn't
approved those changes. Moreover, it is not acceptable that those restrictions requested by
FERC be imposed to all non-FERC jurisdiction. It is important that NERC consult also the
Canadian jurisdictions about the BES definition.
No
Same comment as for question 1
No
HQT do not agree that sub-100 kV looping should refrain radial exclusion, since it doesn't
carry impact on reliability of the BES, but only on non-BES. Though high voltage below 100 kV
should not constitute a looping, it is much more necessary that medium voltage should not
constitute a looping. According to ANSI and IEEE, medium voltage is 35 kV.
No
Same comment as for question 1
Yes
Yes
The main concern about phase 2 definition is that it reduces more than phase 1 definition the
possibility of exclusions, and that no proper technical analysis had been given to justify or
reduce the proposed threshold. FERC's request should not force obligations on non-US
jurisdiction, but non-US jurisdiction should be consulted equally by NERC.
Individual
Grit Schmieder-Copeland
Pattern Gulf Wind LLC
No
While generators should not be seperated into different categories, and I agree with the
general concept to combine power/generation resources into one inclusion, I disagree with
the lanugage that for dispersed power resources the entire generation facility up to the
generator terminal becomes part part of the BES. The critical load for dispersed power
resources (considering the actual Net Capacity Factors) is apparently reached at an output of
75 MVA. Including equipment such as collector circuits and individual generators that carry
well below the critical load of 20 MVA as applicable to conventional generators does seem
unreasonable and undue and will have very little to do with protecting reliability and the BPS,
but will increase maintenance and operating cost to unjustifieable levels. Only at the point
where the such generation is aggregated and a critical load can be reached would dispersed
power generators meet any criticality to the BPS, but the loss of individual small generators or
collection circuits would not have significant impact on the BPS including causing any
cascading outages. Equipment included in compliance with NERC standards(as handeled in
practise for the past 5+ years) should be limited to the point where generation is aggregated
including the GSU and (if owned/operated by GO/GOP) generator tie-lines.
No
Individual
Thomas Breene
Wisconsin Public Service / Upper Peninsula Power
Yes
Yes
No
WPS believes the 30kV threshold is too low especially when 34.5kV is widely used for
distribution. Additionally, there are numerous instances where 46 kV is appropriately
classified as distribution through application of FERC’s 7-factor test and we suggest a 50 kV
threshold is more appropriate than a 30 kV threshold. The BES operates at various kV classes.
As power density and distance grow, lower voltage classes are rendered ineffective at
transporting bulk electric system power. Therefore, certain voltage classes below 100 kV are
clearly limited in their ability to transport bulk electric power and should be ruled as
distribution facilities under the 2005 FPA.
No
WPS recommends that both I2 and I4 be retained, yet reworded such as this: “I2 – Generating
resource(s) and dispersed power producing resource(s), with gross individual nameplate
rating greater than 20 MVA, including the generator terminals through the high-side of the
generator step-up transformer(s) connected at a voltage of 100 kV or above.” “I4 – For
generating and dispersed power producing facilities with gross plant/facility aggregate
nameplate rating greater than 75 MVA, the bus where the aggregate generation is greater
than 75 MVA and continuing thru the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above. (Note: this does not include the individual generating resources
themselves, or the collector feeder system(s).)” The intent is to focus compliance activity at
the point where power is aggregated to the point (usually a bus) where it becomes significant
to the BES not at small (1 to 2 Mw) generators or distribution level Mw collector systems. The
reliability issue for small generating units whether they are diesels, wind turbines, solar units,
or nuclear modules is not the risk of loss of small independent individual units. The common
mode risk of loss of significant amounts of generation is at the point of aggregation.
Yes
Yes
With E3 and E1 the SDT has created an “opt-out” process instead of an “opt-in” process. Only
a small portion of networked facilities less than 100kV has a material impact on the BES. A
better approach would be to utilize the BES process for exceptions and include those that
have material impact to the BES. Needlessly processing these sub 100kV systems through the
burdensome exclusion process is not an effective use of resources.
Individual
Brian J. Murphy
NextEra Energy
No
Inclusion I2 has been modified to incorporate I4 and I4 was eliminated. This is a good step,
but the wording needs to be revised to recognize the insignificance of the individual wind
turbine generators to the bulk electric system. Here is the proposed re-write: “I2 – Generating
resource(s) and dispersed power producing resources with: a) Gross individual nameplate
rating greater than 20 MVA, including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above; or, b) Gross plant/facility
aggregate nameplate rating greater than 75 MVA, beginning at a bus where the aggregate
generation is greater than 75MVA and continuing thru the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” 100kV bright line: The use of the
100kV bright line is recommended to be continued in the base definition, the inclusions and
exclusions. Specific analysis should be performed to demonstrate the need for change on an
individual basis.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Agree
Transmission Access Policy Study Group
Individual
Jack Stamper
Clark Public Utilities
Agree
Snohomish County PUD
Individual
John Seelke
Public Service Enterprise Group
Yes
Yes
Yes
No
The “Phase 1: Bulk Electric System Definition Reference Document dated April 2103 addresses
I4 on pp. 15-20. These examples to not include the following in the BES: (a) the below 100 kV
collector system; (b) step-up transformers with primary and secondary sides below 100 kV,
and (c) the main GSU that connects at 100 kV to the system. This discrepancy between
traditional generation and dispersed generation needs to be explained so that there is no
discrimination between them with respect to the BES definition.
Yes
Yes
The issue of requiring facilities that connect BES generation to the grid to be included in the
BES was settled by FERC in Order 773. We believe that consistency is needed on the issue of
contiguity; furthermore, this was a Phase 2 issue that SDT is supposed to address per its SAR –
see page 2 of the SAR which states a portion of the scopes as follows: “The NERC Board of
Trustees approved BES Phase 1 definition does not encompass a contiguous BES - Determine
if there is a need to change this position.” For example, the connection of reactive devices to
the grid in the Guidance document (pp. 21-22) are in “black” that “indicates Elements that are
not evaluated for the specific inclusion depicted in the individual diagrams being shown.” The
SDT should complete the activities in its SAR in Phase 2 or explain why it has not.
Individual
John Bee
Exelon and its Affiliates
No
Exelon does not support the changes made to items I2 and I4 in the proposed BES Definition.
By combining items I2 and I4, the BES DT has effectively pulled in dispersed power producing
resource collector system elements which are <100kV and which do not normally carry
>75MVA in aggregate flow. In doing so, the BES DT has inappropriately strayed from the work
plan for Phase 2 as defined in the Phase 2 original and supplemental SARs. In the original
Phase 2 SAR, the BES DT was tasked with providing technical justification for the following
items; 1. Develop a technical justification to set the appropriate threshold for Real and
Reactive Resources necessary for the reliable operation of the Bulk Electric System (BES) 2.
The NERC Board of Trustees approved BES Phase 1 definition does not encompass a
contiguous BES - Determine if there is a need to change this position 3. Determine if there is a
technical justification to revise the current 100 kV bright-line voltage level. 4. Determine if
there is a technical justification to support allowing power flow out of the local network under
certain conditions and if so, what the maximum allowable flow and duration should be
Additionally, the Phase 2 original SAR tasked the BES DT with improving the clarity of the
following items; 1. The relationship between the BES definition and the ERO Statement of
Compliance Registry Criteria established in FERC Order 693 2. The use of the term “non-retail
generation” 3. The language for Inclusion I4 on dispersed power resources 4. The appropriate
‘points of demarcation’ between Transmission, Generation, and Distribution Finally, the
supplemental Phase 2 SAR required the BES DT to: 1. Address the directives in FERC Order 773
issued December 20, 2012 The proposed changes to I2 and I4 inappropriately exceed the
work plan as outlined in the SARs because they do not improve clarity for I4 and they are not
in response to a directive from FERC Order 773. In Phase 1, the BES DT intended to exclude
the collector system elements for dispersed power producing resources and stated so
multiple times in responses to stakeholder comments, webinars and in the original draft of
the Guidance document. By changing positions on whether collector systems should be
included in the BES, the BES DT has not improved clarity but has instead materially changed
the BES Definition itself. In addition, in Order No. 773, FERC specifically declined to “direct
NERC to categorically include collector systems pursuant to inclusion I4”. (Order No. 773,
P114). Therefore this change is not in response to a FERC directive. Furthermore, under the
current registration criteria for inclusion in the NERC Registry, Generation Owners and
Generation Operators for individual generation resources >20MVA connected at 100KV or
higher or aggregate resources > 75MVA (Aggregate) connected at 100KV or higher are
required to register and are thus subject to the NERC Reliability Standards. Individual
elements of dispersed power producing resources do not reach these thresholds until the
point of where all of the elements are summed together. The individual dispersed power
producing resource elements before this “summed” point have little or no impact to the BES
as they are generally isolated from the BES behind protection system elements such as relays
and circuit breakers. Exelon feels that only those elements in a collector system that carry
more than 75 MVA of aggregate flow should be included in the BES. Thus, Exelon opposes the
changes to I2 and I4 in the current Phase 2 draft BES definition and has submitted a NEGATIVE
vote on the proposed BES definition.
Individual
Bret Galbraith
Seminole Electric
Yes
Exclusion E1 allows for the exclusion of radials that contain particular amounts of load and
generation resources; however, there is no mention of radials that contain reactive devices.
Therefore, if a radial falls under Exclusion E1(c) for generation and load, but also has a
reactive device, it is unclear whether this Exclusion can be utilized. From past discussions, it
appears that E1(c) covers reactive devices; however, Seminole asks that the SDT revise/clarify
this Exclusion to specifically include reactive devices.
Individual
Jim Cyrulewski
JDRJC Associates LLC
Agree
MISO
Individual
Nazra Gladu
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
No
(1) Although Manitoba Hydro is in general support of the changes, we would like to include
the following clarifying comment: Implementation Plan, Effective Dates - replace the words
“go into effect” with “become effective”. Moreover, append the wording, after “applicable
regulatory approval”: “, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.” Prior to the wording “In those jurisdiction….”. The same
changes should be made to the first sentence in the Effective Date Section of the proposed
Definition document.
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
Yes
The Public Utility District No.1 of Snohomish County agrees the SDT has addressed the
directive, but continues to believe the conditions on outflow and through flow are excessively
restrictive. Please see further comments in the response to Question 6.
Yes
The Public Utility District No.1 of Snohomish County suggests increasing the 30kV threshold to
“35kV or less” as 34.5kV is a common distribution voltage used in rural communities and
should not be classified as BES. From Wikipedia “Rural electrification systems, in contrast to
urban systems, tend to use higher distribution voltages because of the longer distances
covered by distribution lines (see Rural Electrification Administration). 7.2, 12.47, 25, and 34.5
kV distribution is common in the United States…”
Yes
The Public Utility District No.1 of Snohomish County supports the SDT’s approach and
recommends increasing the voltage from “30 kV or less” to “35 kV or less” noted in Question
1.
No
The Public Utility District No.1 of Snohomish County supports the omitted I4 and does not
support the revisions to the generation resources and dispersed power resources inclusions.
The change will classify systems as BES that interconnects a generation unit with a peak
generation capability of less than 2 MVA and typical capacity factor of 25-30 percent. It is
difficult to understand how these types of systems could be considered bulk. A greater than
75 MVA plant would typically have many miles of a 34.5 kV collector system connecting
480/690 volt to 34.5 kV generator step up transformers. Failure or mis-operations of these
collector system components would equate to the loss of a MW or two, 30 percent of the
time. The Public Utility District No.1 of Snohomish County does not believe enforcing NERC
Reliability Standards on these, or similar systems supports reliability. In fact it could stifle
green distributed generation developments.
Yes
The Public Utility District No.1 of Snohomish County supports the SDT's approach.
Yes
The Public Utility District No.1 of Snohomish County remains concerned regarding the limits
imposed on local networks. We note that by order 773A, FERC considers this limit to be
absolute with no allowance for minimal reverse flows for even brief periods under multiple
contingencies. While denying rehearing on this issue, FERC specifically invited Phase 2 to
adjust this outcome in paragraph 79 of the order. We also note that the BES Definition
Reference would allow very brief flows out of a local network as long as the integrated hourly
flow was still into the local network. FERC, however, did not rule on the Reference document,
only the definition itself. Even if FERC did allow the language of the Reference document, the
first multiple contingency event that results in out flow or through flow for the better part of
an hour would cause an excluded network to become immediately included, and subject to
standards without any implementation period (assuming 24 months had passed from the
effective date of the definition). The Planning Committee provided several options to SDT on
this matter. We understand the SDT’s reluctance to impose system studies on what is
intended to be a simply determined bright line criterion, but the present exclusion is not very
useful. The Public Utility District No.1 of Snohomish County supports including the option of
perform one element out (“N-1”) contingency at peak conditions or a fixed two year (or
longer) window could be used rather than the most recent two year sliding window suggested
in the reference document. These options would provide more certainty and better support
the reliability of the BES. However it is determined, it should be included within the approved
definition so that the reference document disclaimer does not apply. Non-retail generation
still lacks a definition to be approved by NERC and FERC, even though this item was
specifically included in the approved SAR. We note that the term is defined in the Reference
Document where the disclaimer stating it is not an official position of NERC makes this
definition of little value. While the Reference Document states “Non‐retail generation is any
generation that is not behind a retail customer’s meter,” we continue to hear it defined
without the “not.” It is very important that entities and regions have a common
understanding of the term, and ask the team to include its definition within the BES
definition.
Individual
Joe Tarantino
Sacramento Municipal Utility District
Yes
SMUD agrees the SDT has addressed the Commission’s Directive. However, removal of 100kv
threshold from the first part of E3 but the 100kV reference remains in the second part of the
E3 exclusion which is inconsistent. It is unclear what value the second sentence of the E3
exclusion provides and should be removed from the E3 exclusion.
No
I2 is inconsistent with E1& E3 by not including “non-retail” generation. E1-b & c and E3-a
contain redundant statements regarding the 75MVA generator threshold. These statements
should be corrected for clarity and consistency.
Yes
SMUD supports the SDT’s approach but believes it to be prudent for the DT to increase the
voltage threshold to avoid unnecessary inclusions of rural electrical systems.
No
SMUD supports the omitted Inclusion-I4 but does not fully agree with the revisions for
Inclusion-I2. SMUD is concerned regarding Inclusion-I2 that now includes a common BES
determination for components of hydro/thermal AND wind/solar resources. Since Inclusion-I2
establishes a 100 kV or above threshold for generators, this draft’s current language would
exclude many of the ‘dispersed resources’. If it is determined that the ‘dispersed resource’ are
subject to BES through ‘multiple step-up transformer’, the current draft language would
inappropriately expand the BES Definition to potentially include all generators regardless of
voltage level when subcategories I2a & I2b are met. Instead, to eliminate this potential
expansion SMUD urges the BES SDT to create an Inclusion that defines an element(s) as BES
where a single component(s) has the potential to removes 75 MVA of resources and remove
the ‘dispersed power producing resources’ from Inclusion-I2. The 75 MVA threshold would
eliminate the administrative and cost burden associated with testing and documentation for
‘small-scale’ machines that are connected to sub-100 kV, are less than 3 MW, and, individually
have little or no impact to reliability of the BES. Subjecting the ‘collector system’ that typically
consist of several miles of radial 34.5 kV, its system components and its dispersed generation
resources to the BES and subsequent application of NERC Reliability Standards would not
provide a proportionate impact to reliability.
Yes
Yes
SMUD remains concerned regarding the limits imposed on local networks. We note that by
order 773A, FERC considers this limit to be absolute with no allowance for minimal reverse
flows for even brief periods under multiple contingencies. While denying rehearing on this
issue, FERC specifically invited Phase 2 to adjust this outcome in paragraph 79 of the order.
We also note that the BES Definition Reference would allow very brief flows out of a local
network as long as the integrated hourly flow was still into the local network. FERC, however,
did not rule on the Reference document, only the definition itself. Even if FERC did allow the
language of the Reference document, the first multiple contingency event that results in out
flow or through flow for the better part of an hour would cause an excluded network to
become immediately included, and subject to standards without any implementation period
(assuming 24 months had passed from the effective date of the definition). The Planning
Committee provided several options to SDT on this matter. We understand the SDT’s
reluctance to impose system studies on what is intended to be a simply determined bright
line criterion, but the present exclusion is not very useful. SMUD supports including the
option of perform one element out (“N-1”) contingency at peak conditions or a fixed two year
(or longer) window could be used rather than the most recent two year sliding window
suggested in the reference document. These options would provide more certainty and better
support the reliability of the BES. However it is determined, it should be included within the
approved definition so that the reference document disclaimer does not apply. Non-retail
generation still lacks a definition to be approved by NERC and FERC, even though this this
item was specifically included in the approved SAR. We note that the term is defined in the
Reference Document where the disclaimer stating it is not an official position of NERC makes
this definition of little value. While the Reference Document states “Non‐retail generation is
any generation that is NOT behind a retail customer’s meter,” we continue to hear it defined
without the “not.” It is very important that entities and regions have a common
understanding of the term, and ask the team to include its definition within the BES
definition.
Individual
Kayleigh Wilkerson
Lincoln Electric System
Agree
MRO NSRF
Group
MRO NERC Standards Review Forum (NSRF)
Russel Mountjoy
Yes
Yes
The NSRF would like clarification on Blackstart resources that are connected at < 100kV. A
Blackstart resource would be included in the BES per I3; however the path that is less than
100kV would not be included in the BES
No
The NSRF believes the 30kV threshold is too low and the SDT justification is inadequate. The
BES operates at various kV classes. As power density and distance grow, lower voltage classes
are rendered ineffective at transporting bulk electric system power. Therefore, certain voltage
classes below 100 kV are clearly limited in their ability to transport bulk electric power and
should be ruled as distribution facilities under the 2005 FPA. MRO members have expertise in
performing interconnected system modeling & operational analysis which indicates that all
three attributes comprising the technical justification used by the SDT are always satisfied
with the 60kV threshold. The recommended 60kV threshold recognizes that 69kV is the
lowest voltage at which loops between radial systems have the potential to support adequate
amount of power transfer under certain worst case scenarios and thus may impact the
>100kV system performance/reliability. In other words, system modeling & operational
analysis experience indicates that 69kV is the lowest voltage at which loops between radial
systems present any possibility that any one of the three attributes in the SDT’s technical
justification may not be satisfied. Or another consideration would be the Transmission
Distribution Factor (TDF) or percent participation. For example, entities could consider 24 – 69
kV facilities with a 0.2 to 0.3% TDF and 50% or greater normalized transfer factor or 50% or
more participation.
No
The NSRF recommends that both I2 and I4 be retained, yet reworded such as this: “I2 –
Generating resource(s) and dispersed power producing resource(s), with gross individual
nameplate rating greater than 20 MVA, including the generator terminals through the highside of the generator step-up transformer(s) connected at a voltage of 100 kV or above.” “I4 –
For generating and dispersed power producing facilities with gross plant/facility aggregate
nameplate rating greater than 75 MVA, the bus where the aggregate generation is greater
than 75 MVA and continuing thru the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above. (Note: this does not include the individual generating resources
themselves, or the collector feeder system(s).)” The intent is to focus compliance activity at
the point where power is aggregated to the point (usually a bus) where it becomes significant
to the BES not at small (1 to 2 Mw) generators or distribution level Mw collector systems.
However, if I2 moves forward as drafted, we feel it is imperative to launch an effort similar to
the GOTO/Project 2010-07, to modify and add clarity to standards as they would apply to a
dispersed power resource. This is important, as many of the current GO/GOP standards would
be difficult and impractical to apply to a dispersed power resource. In addition, we
recommend that interim compliance application guidance be developed to help owners and
operators of dispersed power resources understand how to apply current standards, while
also providing guidance to the auditors. The inclusion of small individual generators will drive
significant industry burden to comply without producing any additional system reliability
benefits. The inclusion of 1 – 2 MW units as separate NERC BES elements will drive
unintended consequences for NERC standards and perhaps the wind industry as a whole as
companies are suddenly subjected to large populations of elements for standards such as
PRC-004, PRC-005, FAC-008-3, TOP-002 R14, and VAR-002 (there may be others). The
reliability issue for small generating units whether they are diesels, wind turbines, solar units,
or nuclear modules is not the risk loss of small independent individual units, it is the common
mode risk loss of significant amounts of generation at the point of aggregation of >75MVA.
Yes
Yes
With E1 (and E3) the SDT has created and “opt-out” process instead of an “opt-in” process.
Only a small portion of networked facilities less than 100kV has a material impact on the BES.
A better approach would be to utilize the BES process for exceptions and include those that
have material impact to the BES. Needlessly processing these sub 100kV systems through the
burdensome exclusion process is not effective use of resources. Please clarify that E1 and E3
are to be applied for normal (intact) system conditions. Rewording suggestions are: E1 - Radial
systems: A group of contiguous transmission Elements that emanates from a single point of
connection of 100 kV or higher “under normal conditions…” E3 - Local networks (LN): A group
of contiguous transmission Elements operated at less than 300 kV “under normal conditions”
that distribute power to Load rather than transfer bulk power across the interconnected
system.
Individual
Daniela Hammons
CenterPoint Energy
No
CenterPoint Energy recommends the voltage level of “30 kV or less” in Note 2 be changed to
“35 kV or less”. Based on this change, Note 2 would be: “The presence of a contiguous loop,
operated at a voltage level of 35 kV or less, between configurations being considered as radial
systems, does not affect this exclusion.” We suggest the voltage level should be established
based on whether the contiguous loop is operated at common distribution voltages (e.g.,
12.47 and 34.5 kV). The vast majority of distribution feeders are, of course, operated radially.
Distribution feeders that are operated as a contiguous loop, or “networked”, are equipped
with “network protectors” that initiate tripping of interrupting devices. A network protector
automatically disconnects its associated power transformer from the secondary network
when the power starts flowing in the reverse direction; that is, the interrupting device opens
if the secondary grid back-feeds through the transformer to supply power to the primary grid.
Therefore, there cannot be any loop flows between radial systems, as network protectors
prevent such flows.
Group
Tennessee Valley Authority
Dennis Chastain
Yes
Yes
No
We agree with the approach, but not the voltage level chosen. Including loops greater than 30
kV will be unreasonably burdensome. We believe the threshold should be 70 kV. Any loops
greater than 70 kV, that could affect the BES, should be added through the exception process.
Yes
Yes
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
Yes
We agree in general but if a technical justification can be developed, we recommend a
threshold of 70 kV.
No
We agree in general but the SDT should review solar, fuel cell, and other DC technologies to
clarify the term "generator terminals" in regards to the PRC standards. Additionally,
clarification should be made that limits the inclusion to the greatest contingency loss, i.e. the
step up transformer to the grid.
No
Change the wording in E-4 from "installed" to "operated". Change the wording in E-3c from
"part" to "element". Change "permanent Flowgate" to "permanent Reliability type Flowgate".
The Eastern Interconnection Book of Flowgates differentiates between "informational" and
"Reliability" type Flowgates.
Group
SERC EC Planning Standards Subcommittee
Jim Kelley
Yes
Yes
Yes
If technical justification can be developed, a threshold of 70kV is recommended.
No
We agree in general but the SDT should review solar, fuel cell and other DC technologies to
clarify the term "generator terminals" in regards to the PRC standards. Additionally,
clarification should be made that limits inclusion to the greatest contingency loss which is the
step-up transformer to the grid.
No
E4 change the word "installed" to "operated". E3c change "part" to "element" and add
"Reliability type" to the statement: permanent Reliability type Flowgate. The rationale is that
the Eastern Interconnection Book of Flow gates contains some entries flagged "informational"
and this would differentiate between the flow gates (reliability versus informational). The
comments expressed herein represent a consensus of the views of the above named
members of the SERC Planning Standards Subcommittee (PSS) only and should not be
construed as the position of the SERC Reliability Corporation, or its board or its officers.
No
Group
National Grid
Michael Jones
No
The version of exclusion E3 criterion (c) filed with FERC January 25, 2012 (RM12-6-000)
requires a “local network” not to contain a monitored facility of a permanent flowgate in the
Eastern Interconnection, a major transfer path within the Western Interconnection, or a
comparable monitored facility in the ERCOT or Quebec Interconnections, and is not a
monitored facility included in an Interconnection Reliability Operating Limit (IROL). By
changing exclusion E3 criterion (c) from “a monitored Facility of a permanent Flowgate…” to
“any part of a permanent Flowgate…” the definition became vaguer and could allow for too
broad of a reading. The original language from Phase 1 of the BES definition regarding
exclusion E3 criterion (c) provided more clarity and guidance on how to apply this exclusion. It
is recommended that the original language from Phase 1 of the BES definition be re-instated.
Facilities should be included only if the elements of the Facility are transferring power (flow)
through a flowgate, transfer path, or IROL.
No
In a similar way as 100 kV is the delineator between the medium and high system voltage
classes in the American National Standards Institute (ANSI) standard on voltage ratings
(C84.1), the voltage threshold in note 2 of exclusion E1 should be based on a well defined
standard system voltage classes to better correlate to operational and system design
considerations and practices. This could e.g., be done by aligning the voltage threshold with
the insulator classes as defined in ANSI standard on insulators (C29.13) or the maximum rated
voltage in Institute of Electrical and Electronics Engineers (IEEE) standards for medium voltage
switchgear (C37.20.2 and C37.20.4). Based on ANSI C29.13, the threshold in note 2 of
exclusion E1 could be set to 46 kV. The Exception Procedure could be used to include lower
(than 100 kV; bright line) voltage systems in the BES envelope when interactions between
these systems and the BES are deemed critical to reliable operations in their local or regional
area.
Group
seattle city light
paul haase
Agree
Snohomish Public Utility District
Individual
Roger Dufresne
Hydro-Québec Production
Agree
Hydro-Québec TransÉnergie Division
Individual
David Burke
Orange and Rockland Utilities Inc.
Yes
No
We generally agree with the Guidance Document that was provided by NERC Drafting Team.
The document showed that if there are any I2 Elements within a local network, the specific I2
Elements are deemed to be BES Elements, but the rest of the local network would still be
qualified as Exclusion E3.
No
We generally agree with the Drafting Team to introduce a threshold to Exclusion E1 but
believe the Step 1 in the Low Voltage Level Criteria is arbitrary. ORU (RECO) is the owner of
the lowest threshold facility at 34kV facilities. The ORU (RECO) facilities at 34kV and 69kV
facilities do not have an impact on the BES. Our opinion is that the 30 kV threshold is too low,
therefore, we are requesting that the Drafting Team consider a higher voltage level as a new
threshold. If a monitored element/facility at a lower voltage (sub-100 kV) level (including
monitored Flowgates) does not pose any impact to BES system, such element/facility should
not be considered as a criteria in E1 or E3.
Yes
Individual
Don Jones
Texas Reliability Entity
No
(1) The current draft appears to disallow E1 and E3 exclusions based on the presence of retail
generation (such as generation within industrial facilities) within a radial system or local
network. This is because the language of I2 does not distinguish between retail generation
and non-retail generation. We do not think the current language reflects the intention of the
drafting team. (2) Consider the following situation: an industrial facility is connected to the
BES at one point with 100 MVA of retail generation connected at 138 kV that never provides
more than 25 MVA to the grid. That generation is identified in I2, but it is excluded by E2, so it
is not BES generation. However, the radial transmission facilities do not qualify as a “radial
system” because of the presence of “generation resources [] identified in Inclusions I2 or I3.”
(3) This can be corrected by (a) referring to E2 in I2 (perhaps add to I2: “unless excluded by
application of Exclusion E2”) ; or (b) referring to “BES generation” in E1 and E3 rather than
merely referring to “I2.”
No
We cannot support this proposal without an adequate technical justification provided prior to
the ballot. The posted materials indicate that the 30 kV threshold was “based on initial
discussions by sub-team; more discussion and analysis needed.” Those materials only provide
a rough outline of the analysis that could be done; they do not indicate that any such analysis
was actually done, and they do not provide a technical justification. Also, there is no
explanation of how the current proposal is “equally effective and efficient” as applied to the
Commission’s stated concerns.
No
(1) We have no objection to combining conventional and dispersed generating facilities into
one BES inclusion, but we do object to the characterization (in the blue box) of wind farms as
“small-scale power generation technologies.” In the ERCOT region there is now over 10,000
MW of installed wind capacity. Wind generation sometimes has served up to 25% of the
entire ERCOT load, and wind provided over 9% of energy produced in ERCOT in 2012. Largescale wind resources (facilities over 75 MVA) must be included within the BES and subject to
appropriate reliability standards. (2) We would like to see clarification that dispersed power
producing resources are generally viewed in the aggregate rather than as separate BES
elements. The performance of each individual wind turbine and element of the collector
system is not a large concern, but we are concerned about the reliability impact of 75+ MVA
of generation connected to the transmission system. We encourage the team to consider
viewing a BES wind farm as an aggregated generating facility, including the turbines, the
collector system, and the step-up transformer. Such an aggregated generating resource
should have an associated GO and GOP, and be subject to appropriate reliability standards.
Yes
We would like to see a revised Reference Document (and any white papers) posted prior to
the ballot so we can fully understand how NERC intends to implement the revised definition
before voting. There were some surprises in the Reference Document after Phase 1 was
approved by NERC. A revised Reference Document should be part of the ballot package so
that all Ballot Pool members can understand exactly what they are voting for (and so the
NERC Board can understand what it is approving).
Individual
Marie Knox
MISO
Agree
ISO/RTO Council - Standards Review Committee
Individual
Saul Rojas
New York Power Authority
No
Removal of 100kv threshold from the first part of E3 but the 100kV reference remains in the
second part of the E3 exclusion which is inconsistent. It is unclear what value the second
sentence of the E3 exclusion provides and should be removed from the E3 exclusion.
No
I2 is inconsistent with E1& E3 by not including “non-retail” generation. E1b&c and E3a contain
redundant statements regarding the 75MVA generator threshold. These statements should
be corrected for clarity and consistency.
No
The 30kV threshold is too restrictive and the sub-100kV loop threshold should be determined
by the method the SDT utilized by regional transmission system makeup. This exclusion and
restrictive loop threshold could lead to additional exception requests.
No
It should be considered that dispersed generators that are represented to the marketplace or
modeled in study cases as 20MVA or higher should be included in the definition just as a
single traditional generating unit of 20 MVA is included. By removing I4, the aggregating
portion of the inclusion seems to be less clear. One suggestion would be to add I2-c to include
dispersed resources that are aggregated and modeled at 20MVA or higher are included. This
would add clarity and consistency to the definition.
Yes
No comments.
Yes
Phase 2 of the BES definition process was supposed to address the 100kV threshold, the
generator thresholds and the reactive resource thresholds for inclusion or exclusion. No
formal studies have shown that these numbers are the correct numbers for this definition.
The studies provided under phase 2 had no more technical justification than those discussions
by the SDT under phase 1. Being able to have that technical justification provides the support
necessary to maintain a reliable transmission system and provides a basis for analysis of
reliability by industry participants.
Group
SPP Standards Review Group
Robert Rhodes
Yes
Please see our comment in Question 6 regarding removal of the 100 kV limit?
Yes
Please see our comment in Question 6 regarding removal of the 100 kV limit?
No
It is difficult to agree with the approach when the details of the evaluation and analyses that
were performed have not been made available for review by the industry. Once these details
are known and have been reviewed by the industry, a more informed decision on what
voltage level should be incorporated into the exclusion can be made. As it stands, we are very
uncomfortable with the 30 kV limit and feel it is too low. Is the contiguous loop referenced in
Note 2 normally closed or normally open? Whichever, it needs to be clarified in the note.
Yes
Yes
Yes
E3 has been changed in response to a FERC directive to remove the lower bound for LNs of
100 kV. While the removal does directly address the directive from FERC, the removal of the
100 kV lower limit may bring other questions, issues and uncertainty into consideration. In E1,
the SDT developed an alternative response to a directive which appears to be a very good
work-around. Although we don’t have specific language to offer, could the SDT develop a
similar alternative for E3 without totally eliminating the existing 100 kV limit? Regarding the
30 kV limit in Note 2 of E1, does incorporating this value in the Note imply or could it be
interpreted that these particular 30-100 kV looping facilities would become part of the BES?
Although they aren’t specifically addressed in any of the Inclusions, perhaps it would be
appropriate to specifically state that they would not be included. If an entity had two 115 kV
radial lines and adds a looping 34.5 kV line between them that is operated normally closed,
are these facilities considered radial lines subject to E1 or Local Networks subject to E3?
Individual
Joylyn Faust
Consumers Energy Company
Consumers Energy provides comments on the following issue raised by the Phase 2 BES
definition: (1) the changes proposed to Inclusions I2 and I4. Dispersed Power Producing
Resources Should Not Be Treated the Same as Other Generation Because They Do Not Have
the Same Impact on the BES. The Phase 2 BES definition proposes to entirely eliminate
Inclusion I4 and revise Inclusion I2 to, among other changes, include dispersed power
producing resources. Consumers Energy does not agree with this change because different
generating resources have different impacts on the BES, and thus are entitled to different
treatment. This change is primarily premised on the theory that NERC should treat all power
generation sources equally. While this theory sounds appealing upon first blush, it ignores the
reality that different generation sources are in fact not equal because they differently impact
the BES. In the case of dispersed power producing resources, the potential impact on the BES
of these resources is not the same as a larger power producing resource (e.g. a 500 MW coal
unit). The unexpected addition or loss of a larger generating unit can majorly impact the
reliability of the BES. The addition or loss of a single unit (e.g., a 1.4 MW wind turbine), or
even several smaller units, has little, if any, material impact on the BES. Because of differing
impacts on the BES, dispersed power producing resources are entitled to different treatment.
In addition, merely adding the phrase “and dispersed power producing resources” to I2
significantly expands the scope of assets drawn into the BES. Under the Phase 1 definition,
only the generating units themselves were included in the BES (see, e.g., Figure I4-1 of NERC’s
“Phase 1: Bulk Electric System Definition Reference Document” dated April 2013). The Phase 1
definition did not include all of the equipment between the generator terminal through the
high-side of the step-up transformer. This exclusion of certain equipment was for good reason
– dispersed power producing resources do not individually have significant impact on the BES,
and only collectively have an impact. Under the proposed Phase 2 definition, the entire
dispersed power producing facility (e.g., an entire wind farm) will be included in the BES.
While we appreciate that such an expansion was likely the Drafting Team’s intent, this
expansion makes little sense. Dispersed power producing resources simply do not – until
aggregated – have sufficient impact on the BES to warrant such an expansion of the scope of
the BES. A better approach would be to limit the scope of the BES to only include equipment
from the point where the aggregated generation achieves 75 MVA – i.e., from the substation
bus where the collector circuits aggregate to exceed 75 MVA. As such, Consumers Energy
proposes that NERC retain Inclusion I4, but change its wording to something like this:
“Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system design primarily for aggregating capacity, from
the connection point at a voltage of 100 kV or above down through the connecting
transformer to a single common point of aggregation.” This approach reasonably limits the
BES definition as applied to dispersed power producing units in a fashion proportional to their
impact on the BES.
Yes
Consumers Energy provides comments on the following issue raised by the Phase 2 BES
definition: 2) a recommended change to Inclusion I3. Inclusion I3 Should Exclude Blackstart
Resources Connected to the BES Only On A Very Limited Basis The Phase 2 BES definition (and
the Phase 1 BES definition) in Inclusion I3 provides that all Blackstart Resources identified in
the Transmission Operator’s restoration plan are part of the BES. NERC should modify
Inclusion I3 to exclude Blackstart Resources that are only connected to the BES on a very
limited basis. NERC should impose requirements on an asset proportional to the asset’s
impact on the BES. As such, assets that have little-to-no impact on the BES should be subject
to only minimal requirements. In the case of Blackstart Resources, some such resources have
extremely little impact on the BES during a typical day. For example, some gas peaker units
are only connected to the BES for less than 24 hours in a year because they are used only
during extreme weather conditions or when the system is actually “black.” Given their low
impact on the BES, NERC should regulate these units in a way proportional to their limited
use. Therefore, Consumers Energy proposes that NERC modify Inclusion I3 to cover
“Blackstart Resources identified in the Transmission Operator’s restoration plan, unless such a
resource is connected to the Bulk Electric System for less than 24 hours per year.” This
modification would provide the regulation in proportion to these units’ impact on the BES.
CONCLUSION: WHEREFORE, Consumers Energy Company urges NERC and the Standard
Drafting Team for Project 2010-17 to reflect on these comments in developing the proposed
Phase 2 BES definition.
Individual
Michelle D'Antuono
Occidental Energy Ventures Corp.
No
Occidental Energy Ventures Corp. (on behalf of all Occidental NERC Registered Entities)
(“OEVC”) believes that the literal application of FERC’s directive creates vulnerabilities that
must be addressed. First, E3 as proposed will require that no energy may flow out of the Local
Network for any reason. This would include Reactive Power which is essential to supporting
local system voltage. It is not inconceivable that entities will take steps to eliminate Reactive
Power export in order to avoid the costs of reliability compliance. Similarly, there is no relief
in exclusion E3 for the unintended outflow of energy under multiple contingency conditions.
Already in Orders 773 and 773-A, FERC has taken a stance that there are no acceptable
scenarios where an excluded Local Network may do so. We believe this is unreasonable, adds
excessive costs, and does little to reduce Bulk Electric System risk. FERC’s very conservative
“no-exceptions” view will prevail by default if the drafting team does not provide the
alternative language in the guideline document – and shown below for reference: “Real
power flows only in the LN from every point of connection to the BES for the system as
planned with all‐lines in service and also for first contingency conditions as per TPL‐001‐2,
Steady State & Stability Performance Planning Events P0, P1, and P2, and the LN does not
transfer energy originating outside the LN for delivery through the LN to the BES.”
No
Although OEVC believes the language changes for E1 and E3 adequately addresses the FERC
directive, some entities have expressed a need for clarity when considering E1 and E3 for
cogeneration that would normally be excluded by application of E2. As OEVC understands the
position of these entities, the logic of applying I2, then E2, and finally E1 or E3 according to
the hierarchy could include, then exclude, and then re-include an industrial generator that
would otherwise qualify for Exclusion E2. OEVC understands from the Webinar that this is not
the intent of the SDT and that clarification will be made so that no one can misinterpret the
SDT’s intent. Also, the language in E3 might be interpreted to mean that ANY BES generation
within an LN would disqualify the entity from claiming the E3 exclusion. It would seem that
only the pathway from the BES generator to the BES should be included in the BES to satisfy
the FERC directive and that the remainder of the LN might still qualify. (Perhaps this will be
clarified in the Guidance Document). Finally, it still seems unnecessary to limit non-retail
generation within the LN to 75 MVA when FERC has now stated that power cannot flow out of
the LN under any conditions.
No
OEVC agrees in general with the approach taken by the SDT to derive the 30 kV limit. At some
point, a practical limitation of the ability to evaluate the performance of the low-voltage
system dictates that a threshold be set. Taken to the absurd logical extreme, without Note 2,
the radial exclusion could be applied only after every 115 volt household connection was
evaluated. However, without a view into the study results, we have no way to assess whether
the 30 kV limit makes the most sense. We fully respect the project team’s judgment, but it
seems like this limit could easily be set at 70 kV without any noticeable reliability impact.
Yes
No
Group
Cooper Compliance Corp
Mary Jo Cooper
Yes
No
We agree that the Exclusion E3 is correct providing Including I2 is modified. We recommend
that I2 is further clarified to include a more specific definition of a Generator Interconnection
Facility (Transmission Interface) and provide clarification that the generation counted against
the “aggregate capacity of non-retail less than or equal to 75 MVA (gross nameplate rating)”
that disqualifies the radial exclusion in E1 or the local area network exclusion E3. Regarding
the Transmission Interface, FERC recommendations contained in Docket No. RM12-16-000
define the Standards applicable to the Transmission Interface. These Standards are FAC-0011, FAC-003-3, PRC_004-2.1a, and PRC-005-1.1b. We have identified a potential gap in which a
generator is connected to a portion of a 115 kV line owned by a distribution provider prior to
connecting to what otherwise would be considered the BES. Absent the generator, the line
would only be used to serve load and would be excluded under E3. We recommend
clarification that does not require the distribution provider to register as a Transmission
Owner and Operator based on the small section of line used as part of the Transmission
Interface. Instead, we recommend that the distribution line also qualifies as a generator
interconnection facility and is part of the transmission interface to the generator only. The
following are our recommended changes to Inclusion I2. Generating resource(s) and
dispersed power producing resources connected at voltage of 100kV or above, including the
Generator Interconnection Facilities with: a) Gross individual nameplate rating greater than
20 MVA, OR, b) Gross plan/facility aggregate nameplate rating greater than 75 MVA. The
Generator Interconnection Facilities include the generator terminals through the point of
interconnection to the transmission elements that would otherwise be considered
transmission elements included within the definition of Bulk Electric System. Regarding the
clarification on what is counted towards the 75 MVA that disqualifies the radial or local area
network exclusions, we believe it is the drafting teams intent that the count of generation is
only to include generation that has been defined within the Inclusions or through the
exception process. However, we feel the actual definition could be enhanced to provide this
clarification. In separate comments made by the City of Anaheim they propose the following
modifications to the definition, which we agree better defines this definition. Exclusion E1: E1
– Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and satisfies one of the following additional criteria: a)
The radial system only serves Load. b) If the radial system includes only generation resources,
the generation resources (i) must not satisfy the criteria set forth in either Inclusion I2 or
Inclusion I3 and (ii) must not have an aggregate capacity of greater than 75 MVA (gross
nameplate rating) directly connected to the radial system at a voltage of 100 kV or above. c) If
the radial system both serves Load and includes generation resources, the generation
resources (i) must not satisfy the criteria set forth in either Inclusion I2 or Inclusion I3 and (ii)
must not have an aggregate capacity of greater than 75 MVA (gross nameplate rating) of nonretail generation directly connected to the radial system at a voltage of 100 kV or above.
Exclusion E3: E3 – Local networks (LN): A group of contiguous transmission Elements operated
at less than 300 kV that distribute power to Load rather than transfer bulk power across the
interconnected system. LNs emanate from multiple points of connection at 100 kV or higher
to improve the level of service to retail customs and not to accommodate bulk power transfer
across the interconnected system. The LN is characterized by all of the following: a) Limits on
connected generation: The LN does not include generation resources identified in Inclusions
I2 or I3 and does not have an aggregate capacity of more than 75 MVA (gross nameplate
rating) of non-retail generation directly connected to the LN at a voltage of 100 kV or above.
b) Power flows into the LN; it rarely, if ever, flows out. The LN does not transfer energy
originating outside of the LN for delivery through the LN.
Yes
No
See comment to question No. 2.
Yes
Yes
We recommend that the drafting team address what qualifies as a generator Interconnection
Facility (Transmission Interface) for those radial lines that connect generation while
addressing FERCs concern that generation has to be continuous. We do not believe that
distribution facilities that serve load and that also have generation connected to it at 100 kV
or above should automatically qualify as Transmission. We recommend that those facilities
are Transmission Interface facilities and instead should be treated in the same manner as a
Generator Interconnection Facility. We ask that the drafting team include within the
definition of Bulk Electric System, the sub BES system otherwise known as the Transmission
Interface. We propose the following definition of Transmission Interface: A Transmission
Interface are the transmission line continuous from the generation identified in Inclusion I2
and I3 and the static or dynamic devices identified in I5 that absent the generation, static, or
dynamic devices would be excluded under E1.
Group
City of Tacoma
Chang Choi
Yes
Yes
Yes
Comments: Many utilities utilize 35 kV distribution radial networks from a 2 or 3 transformer
bank source. TPWR supports raising the 30 kV threshold to 35 kV.
No
TPWR supports the omitted I4 and does not support the revisions to the generation resources
and dispersed power resources inclusions. The change will classify systems as BES that
interconnects a generation unit with a peak generation capability of less than 2 MVA and
typical capacity factor of 25-35 percent. It is difficult to understand how these small
generation systems could be considered BES.
Yes
Yes
TPWR remains concerned regarding the limits imposed by b) on local networks. We note that
by order 773A, FERC considers this limit to be absolute with no allowance for minimal reverse
flows for even brief periods under multiple contingencies. While denying rehearing on this
issue, FERC specifically invited Phase 2 to adjust this outcome in paragraph 79 of the order.
We also note that the BES Definition Reference would allow very brief flows out of a local
network as long as the integrated hourly flow was still into the local network. There is no
phase in period for a facility that loses its BES exclusion. For example, should a local network
experience multiple contingencies that causes an unusual power flow disqualifying its
exclusion, then 24 months should be allowed to resume BES applicability.
Group
PacifiCorp
Ryan Millard
Yes
No
Although PacifiCorp believes that the SDT has addressed the FERC directive, the directive in
general allows for equivalent viable alternatives. PacifiCorp believes that FERC’s directive is
overreaching and fails to consider the already minimal upper limit of 75 MVA (gross
nameplate rating) established in Exclusion E1. A generating resource’s registration status or
BES status should not have a bearing as to whether it must have a contiguous path to the BES.
The previous limited upper limit of 75 MVA established a point at which the registered
generator(s) would not interfere with the reliable operation of the interconnected system in
the event of a loss of the < 75 MVA generator(s) or of the < 75 MVA generator’s(s’) ability to
respond to the loss of critical generation elsewhere in the system. In the relatively few
situations in which the registered generating resource is critical to the operation of the
interconnected system, the associated transmission could be included within the scope of the
BES through the approved exception process.
Yes
While the proposal is currently limited to a voltage level of 30 kV or less, PacifiCorp suggests
an expansion of the language to include minimum voltage levels based on the characteristics
of each interconnection (e.g., 30 kV for the Eastern Interconnection and 40 kV for the
Western Interconnection).
No
PacifiCorp does not agree with the proposed changes to Inclusions I2 and I4 because such
changes would include generating resources within the BES regardless of a resource’s
individual MVA rating and all of the equipment from each generator terminal to the > 100 kV
transmission interconnection if the facility aggregate rating exceeds 75 MVA. A similar
outcome was included in the Phase I definition in the previous version of Inclusion I4 that
addressed dispersed power producing resources specifically and, as a result, one of the SDT’s
tasks in the Phase 2 SAR was to address the treatment of dispersed power producing
resources. A dispersed power generating facility necessarily consists of individual units of a
limited size to take advantage of the distributed nature of the resource (e.g., wind or solar)
upon which the facility relies for its fuel source. One benefit of such facilities’ unit size and
geographical distribution is that they are not as susceptible to a substantial loss of generating
capability as a single unit of 20 MVA or greater (the registration threshold for a single
generating unit). If the arrayed generators were each 2 MVA then the probability of losing 20
MVA at the generator level would be .00000001%. If the units were 5 MVA each the
probability of losing all four units at the generator level would be .01%. The probability of
losing a single 20 MVA unit would be 10%. These variations illustrate that there will be
different values depending upon the arrayed generator’s size. Given the reliability advantage
this diversity affords it does not seem reasonable to treat this type of facility in the same way
as a single unit facility of 20 MVA or greater. As recognized by the SDT and FERC in Order No.
773, a dispersed generating facility of 75 MVA or greater (NERC Registry Criterion Section
III.c.2) can have an impact on the BES. To recognize this impact and to also account for the
dispersed nature and reliability advantage as described above, PacifiCorp requests that the
SDT strongly consider the following two potential alternative revisions to the proposed
Inclusion I2: PacifiCorp’s preferred option would be: “I2 – Generating resource(s) and
dispersed power producing resources, with: a) Gross individual nameplate rating greater than
20 MVA, including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above, OR, b) Gross plant/facility
aggregate nameplate rating greater than 75 MVA, beginning at a bus where the aggregate
generation is greater than 75 MVA and continuing through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above.” The following diagram
demonstrates the 75 MVA aggregation impacted by PacifiCorp’s preferred option: (diagram
provided to Wendy Muller at NERC). This preferred option would also include traditional
sources of generation comprised of several small generators. NERC’s registration criteria
would still include this type of a facility as a registered GO or GOP. PacifiCorp’s second option
is: “I2 – Generating resource(s) and dispersed power producing resources, including the
generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above with: a) Gross individual nameplate rating greater than 20 MVA,
OR, b) Gross plant/facility aggregate nameplate rating greater than 75 MVA. For facilities with
an aggregate rating of 75MVA or more that consist of individual units rated at 4 MVA or less,
the portion of the facility that is included in the BES as generation shall start at the point at
which the 75MVA or greater aggregation occurs and continue out to the interconnection with
the transmission system rated at 100 kV or more.” Under this proposed change, a dispersed
generating facility of 75 MVA or more consisting of individual generators of 4 MVA or less
would be included in the BES definition as generation resources in a similar manner as other
types of generation resources, but the unique nature of the small, distributed generating
units that comprise them and their inherent reliability advantages would also be
appropriately recognized in the definition. NERC’s registration criteria would still include this
type of a facility as a registered GO or GOP.
No
PacifiCorp does not agree with certain of the SDT’s clarifying changes enumerated above, for
the following reasons: • Item (b): rationale provided in response to question 4 above; and •
Item (d): Reactive Power devices are often installed on substation busses less than 100 kV for
the sole benefit of the retail customers of the utility. If a substation or substation bus is
excluded from the BES through either Exclusion 1 or Exclusion 3 and is installed for the sole
benefit of the retail customers, then that device should also be excluded from the BES.
PacifiCorp offers the following suggested wording for Exclusion E4 for the SDT’s consideration:
Reactive Power devices installed for the sole benefit of retail customers.
No
Individual
Herb Schrayshuen
Self
No
The earlier version of exclusion E3 criterion requires a Local Network not to contain a
monitored facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored facility in the ERCOT or
Quebec Interconnections, and is not a monitored facility included in an IROL. The definition
now is more vague. The original language was better. Facilities should be included in the BES
only if the elements of the Facility are transferring significant amounts of power which would
impact the reliability of the BES.
Yes
No
The 30 kV limit may be too low. 50kV or high limits may be technically justified. An analysis to
support the choice of any limit is needed.
No
Proposal for I2 as follows: I2 - Generating resource(s) and dispersed power producing
resources, including their power delivering assets operated at a voltage of 100 kV or above
with:
No
It is never possible to determine whether a reactive device is for the "sole benefit" of retail
customers. The presence of a reactive device may benefit the retail customer from a rates
perspective or a local voltage perspective, but the presence of the reactive device, no matter
where it is located, even at the distribution level, also provides system wide BES/BPS benefits.
Yes
NERC is an international body. The BES SDT in any next version of the Phase 2 definition
should take full account of Canadian regulatory frameworks. NERC must consider all
jurisdictions. The existing legislated definitions of "distribution" in the Provinces must be
allowed for in any definition of BES even if it is though a "local jurisdiction" exception
footnote.
Group
Pepco Holdings Inc & Affiliates
David Thorne
Yes
Yes
Yes
While we agree this approach addresses the Commissions sub-100 kV loop concerns for radial
systems, the choice of a 30 kV threshold seems somewhat arbitrary. The intent is to allow
small “distribution system” loops between connection points and still satisfy the E1 exclusion
for radial transmission systems. IEEE 100 “The Authoritative Dictionary of IEEE Standard
Terms” defines a Distribution Line as “Electric power lines which distribute power from a main
source substation to consumers, usually at a voltage of 34.5 kV or less.” Based on this industry
standard definition, we believe a 40kV threshold would be more appropriate, so as to allow all
looped distribution circuits, including those operating at 34.5kV, to satisfy Exclusion E1 for
radial systems. Additionally, the rationale box included as part of Note 2 states: “…..As a first
step, regional voltage levels that are monitored on major interfaces, paths and monitored
elements to ensure the reliable operation of the interconnected system…” Just because
elements are monitored, does not necessarily mean that those elements are specifically
critical to the reliable operation of the system. In many cases it is strictly a function of
providing adequate data for the modeling of the system. It would be unlikely that an
underlying distribution loop would have any significant impact on the transmission system. It
may be possible that the underlying loop system may itself have flow problems, but that is
not the same as that loop creating a problem on the transmission system.
Yes
Yes
Yes
There were many suggestions and comments on the first draft of the BES Reference
Document. As the SDT continues to revise the document, it is hoped that the SDT consider
including additional figures to provide for clarification. It is recognized that there are probably
many individual, unique configurations and that every one of them cannot or should not be
included. However, consideration should be given to general clarifications that will aid the
entire industry in understanding the details of the definitions application.
Individual
Donald Weaver
New Brunswick System Operator
Agree
NPCC Reliability Standards Committee
Individual
Randi Nyholm
Minnesota Power
Agree
MRO NERC Standards Review Forum (NSRF)
Individual
Daniel Duff
Liberty Electric Power LLC
Agree
Essential Power
Group
Southwest Power Pool Regional Entity
Emily Pennel
Yes
Yes
Yes
Yes
Yes
No
Group
DTE Electric
Kent Kujala
Yes
Yes
No
30kV is too low, 60kV would be more realistic. The lower the voltage chose the great the
burden on industry in excluding these elements with no corresponding benefit to reliability.
Yes
Yes
No
Individual
Thomas Foltz
American Electric Power
Yes
Yes
No
While AEP does not necessarily disagree with the 30KV threshold, we are however confused
by the concept of a contiguous loop being part of a radial feed, as we find “radial” and “loop”
as mutually exclusive terms. This phrase is ambiguous and needs further clarification before a
voltage threshold can be discussed.
No
AEP does not believe that the generator terminals of individual dispersed power producing
resources should by default be included in the BES definition. We suggest revising I2 to
include dispersed power producing resources from the point of connection where the
resource’s aggregate nameplate rating is greater than 20 MVA through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above. As currently drafted,
individual wind turbines would be included as part of this definition. AEP offers the following
additional reasons why individual wind turbines specifically should not be in scope: *Given
their small size and interment availability of the prime mover, they do not individually
constitute a risk to the reliability of the BES. * The ability of the GO to perform maintenance
and testing activities required by PRC-005-2 is limited due to the physical design of the system
and may also be limited due to warranty agreements with the OEM. * A wind farm may
experience hundreds of breaker operations a day and have not automated ability to
determine whether the operation was caused by a Protection System operation. Under this
scenario, the resources needed to show compliance with the proposed PRC-004-3 may be
unduly burdensome to the GO.
Yes
Yes
Under E3, did the team intend to also eliminate the 100kv threshold from the phrase “LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of
service…”?
Individual
Mike Hirst
Cogentrix Energy Power Management, LLC
Agree
North American Generator Forum: Standards Review Team
Individual
Kenneth A Goldsmith
Alliant Energy
Agree
MRO NSRF
Individual
Jason Snodgrass
Georgia Transmission Corporation
Yes
Yes
Yes
Because of the addition of “dispersed power producing resources” to I2…GTC believes it’s
more appropriate to replace the term “generator” with “resource” in the following phrase:
..."including the generator terminals through the high-side..."
Yes
Yes
GTC recommends the additional clarifier to E4: Reactive Power devices installed for the sole
benefit of a retail or wholesale customer.
Group
Iberdrola USA
Joe Turano
Yes
Yes
Yes
Yes
Yes
It seems counter-intuitive that a 600 MVAR dynamic range SVC directly connected to the 345
kV system would have the 345 kV bus and the 18 kV bus-connected capacitive & reactive
equipment be BES, yet the 345/18 kV transformer would not be BES. The NERC “BES
Definition Reference Document” is an important aid in interpreting different circumstances of
applicability of the BES Definition. It should be kept up to date as the definition changes, with
specific examples of applications of those changes. Specific comments on the “Reference
Document” are: • For BES Exclusion E2 (behind-the-meter customer-owned generation), the
NERC SDT recommends using 1 year of integrated hourly revenue metering to test for flow
into the BES of less than 75 MVA. However, for BES Exclusion E3 (local networks), the NERC
SDT recommends using 2 years of integrated hourly metering to test for flow into the BES at
all points of connection of the candidate local network to the BES. • Several figures seem to
have possible exclusions that are not mentioned, in portions of those figures. Specifically: o
Figures E1-4a, E1-5, and E1-6 have the same 15 MVA, then 10 MVA generator on the middle
left of the diagram that could have its generator lead to the tap point qualify for a radial
exclusion; but the tapped lead is shown as BES. The vertical blue line from the ≥100 kV bus
would still be BES. o Figures E1-7a, E1-8a, E1-9, and E1-10 have either radial loads or industrial
customers with retail generation on the middle left and right of the diagram that could have
their tapped supply lines qualify for a radial exclusion; but the tapped lines are shown as BES.
The vertical blue line from the ≥100 kV bus would still be BES. o Figure S1-9b only considers
the 69 kV network as a candidate for a local network exclusion. This is not a valid
consideration, because whether or not the red arrows point up or down, the 69 kV system is
not BES by nature of the core definition. Moreover, there are not enough points measured to
determine flow polarity of the parallel parts of the 138 kV system. It would be necessary to
either/also measure 2 other points on the 138 kV network for that network to be a candidate
for the local network exclusion. No conclusions or recommendations can be drawn from this
example as shown. Figures S1-10, S1-11, and S1-12 show the entire 138 kV loop on the left of
the diagram as a local network exclusion (shown as green) – as noted above this is not
consistent with FERC Order 773 and 773-A, nor Figures S1-9a and S1-9b.
Group
IRC Standards Review Committee
Greg Campoli
No
We are unable to find the technical justification for removal of the 100kV threshold. We are
unable to support this until the technical basis is presented.
Yes
No
The SDT describes the steps taken that led to proposing the 30 KV limit in Note 2 for which an
entity does not have to consider a loop between two otherwise radial systems. However, the
steps presented are not in our view technical justification for the proposed threshold. Before
we can support this proposal, we would appreciate the SDT provide technical justification as
to why 30kV is the appropriate level but not any other voltage levels, e.g. why not 50kV or
69kV?
Yes
Yes
No
Individual
Diane J. Barney
New York State Department of Public Service
No
While the goal of having some cut off level below which the facilities can clearly be eliminated
from consideration is theoretically reasonable, history has demonstrated the designation can
be abused and used for alternative purposes. There is no technical basis for the 30 kV cut off.
NERC has an obligation to provide technical advice to FERC, so that any number provided to
FERC is interpreted as technical advice. NERC should not include any numbers in any
definition or standard for which it cannot provide a technical basis. Surveys do not provide a
technical basis. Discussions have indicated that because facilities less than 100 kV triggered a
major event in the southwest, a lower level voltage needs to be identified. Note that if either
the current NERC BES definition or a functional analysis had been applied to the system at
issue, either definition approach should have identified the involved facilities as bulk
elements. A lower threshold would therefore be superfluous, and would be over-inclusive to
an even greater degree than the current definition.
Yes
NERC has an obligation to provide technical advice to FERC, so that any number provided to
FERC by NERC is interpreted as technical advice. A major purpose of the BES Phase II effort
was to establish a technical basis for the 100 kV brightline and the 20/75 MVA generation
levels. While NERC has provided a report purportedly providing a technical basis for these
threshold levels, the report fails to do so. NERC should not include any numbers in any
definition or standard for which it cannot provide a technical basis. Surveys do not provide a
technical basis. Particularly troublesome is the presentation of alternatives to the 100 kV
brightline. The report authors looked at 5 alternatives to establishing a technical basis for
determining the bulk system. The report failed to evaluate the methodology historically
applied to the NPCC system. If a major NERC region was able to successfully apply their
methodology, why was it not evaluated and why would it be impossible to expect other
regions to perform a similar analysis as the base for determining the BES?
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Under the premise that the very first paragraph of the BES Definition already establishes the
bottom voltage threshold of 100kV, we agree with removing the mention of the 100kV
bottom threshold in exclusion E3.
Yes
In general we agree with these changes and propose the following alternative language for
more clarity: ‘Generating resource(s) including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above, and dispersed power
producing resources connected at a common point at a voltage of 100 kV or above with;’
No
The IESO does not agree with this approach as we identify two major concerns related to
Note 2 in Exclusion E1. First, by adding a new voltage threshold of 30 kV, a new category of
“wires” operated at voltages between 30 kV and 100 kV which may become part of BES is
effectively created. On the one hand, this would be inconsistent with the BES definition
introductory paragraph (Bulk Electric System (BES): Unless modified by the lists shown below,
all Transmission Elements operated at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher. This does not include facilities used in the local
distribution of electric energy). On the other hand, this could result in a huge effort/cost in
part of all facility owners as it appears that the intent is to include this new category of
“wires” in the BES elements and potentially rely on the BES Exception process to exclude
them one by one. Second, the demarcation point between transmission and distribution may
be different in non FERC jurisdictions, such as Canadian provinces. For example, in Ontario,
legislation establishes 50kV as the technical boundary line between transmission and
distribution. In establishing voltage thresholds, NERC needs to consider non-US legislated
demarcation points, and the standard development process must make allowances for such
regulatory and/or jurisdictional differences. The establishment of the voltage floor for the E1
exclusion is inconsistent with the language and structure of the legislative framework in
Ontario. Furthermore, we believe that the exception process is not appropriate to determine
the jurisdictional issue of whether facilities are part of the bulk power system. Therefore, the
IESO proposal is to remove Note 2 altogether from Exclusion E1 and rely on the BES Exception
process to determine facilities operated below 100 kV that must be included in the BES. In the
alternative that Note 2 in Exclusion E1 is retained, we request that it be modified to read as
follows: “Note 2 – The presence of a contiguous loop, operated at a voltage of 30 kV or less,
between configuration being considered as radial systems, does not affect this exclusion for
US registered entities. For a non-US Registered Entity, the voltage level should be
implemented in a manner consistent with the demarcation points within their respective
regulatory framework.
Yes
In general we agree with these changes and propose the following alternative language for
more clarity: ‘Generating resource(s) including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above, and dispersed power
producing resources connected at a common point at a voltage of 100 kV or above with;’
Yes
Yes
1) NERC must ensure that any new or changes to standards as a result of FERC directives that
apply to load reliability and load supply continuity are limited to the FERC jurisdiction only. In
Canada, local load reliability requirements are under the authority of local regulators such as
the Ontario Energy Board in Ontario. 2) Implementation Plan may result in a conflict with
Ontario regulatory practice with respect to the effective date of the standard. It is suggested
that this conflict be removed by appending the effective date wording, after “applicable
regulatory approval” in the Effective Dates Section of the Implementation Plan, to the
following effect: “, or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.” prior to the wording “In those jurisdiction….”. The same
changes should be made to the first sentence in the Effective Date Section of the proposed
Definition document. 3) In our opinion, SDT has correctly crafted the language in E1 and E3 in
the approved definition. To address some of the FERC concerns, it may be simpler and clean
to introduce a new inclusion “I” for sub 100kV system(s) that are used for bulk power transfer
(not a sink) across the BES from one area to the other.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
No
The change in the question was evidently intended to cover the 34.5 kV interconnection
systems of wind farms, but it also pulls into the BES the 230 kV feeders supplying aux power
for fossil plants (compare Figs. E1-7 and E1-7a in the FERC order 773/773a-amended Guidance
Document). The HV-to-MV transformers for aux loads may be included as well (no per Fig. E17a, yes per SDT inputs in the 6/26/13 webinar if the transformers are of the 2 or 3-winding
type). It makes sense to include in-line components (i.e. the GSU-to- connection point
conductors), but there does not appear to be any justification for adding auxiliary
transformers and their HV feeders to the BES. These are in-house systems that have no
significance for the grid in general. The change to E3 should have been limited to wind farms.
No
See comments above.
Yes
Yes
Yes
Yes
The language of the proposed BES definition is rather convoluted and is therefore difficult to
apply correctly without the Guidance Document. The FERC order 773/773a-amended
Guidance Document is not complete or final for the Phase-2 BES definition. Its exclusion E1
statement is that of phase-1, not Phase-2, for example, and a disclaimer on p.1 states that
“…this reference document is outdated. Revisions to the document will be developed at a
later date to conform to the definition being developed in Phase 2.” It appears that the Phase2 BES definition is being rushed through the approval process, and it would be preferable to
take the time to compile a complete and
Individual
Michael Lowman
Duke Energy
Yes
Yes
Yes
Yes
No
Duke Energy believes the SDT should consider changing the language of E4 to “Reactive
Power devices installed for the benefit of a retail customer(s).”
Yes
Duke Energy believes that ambiguity exists between the industry and FERC within the
language of E1 regarding “single point of connection”. See paragraph 138 and 142 of Order
773. The language “single point of connection” in E1 should be revised for clarity. If E1 is
edited, the change may impact the terminology used (“multiple points of connection”) in E3.
Individual
Jim Thate
Delta-Montrose Electric Association
Yes
The proposed BES definitions need more clarification, and the utilities should be granted
more time for comments and responses.
Individual
Barbara Kedrowski
Wisconsin Electric
No
Wisconsin Electric agrees with the NAGF comments in response to Question 1.
No
Wisconsin Electric supports the comments filed by the NAGF in response to this question with
the following edits: “The equipment being included in the BES definition should only be that
equipment that actually carries greater than 75 MVA – the collector systems, main
transformers, and high-voltage interconnections, not the individual wind turbines.
Implementing standards at the individual wind turbine level (<2 MW in many cases) does not
improve reliability and only creates additional workload for both the registered entities and
the Regions. A 2 MW wind generator will neither have an impact due to the loss of generation
nor cause cascading outages due to a failure to trip a 600 volt machine.
Yes
1. Wisconsin Electric is concerned that the drafting team has not considered the potential
impacts of the proposed definition on other standards or their requirements. For this reason
the definition should be rejected until such time as adequate consideration has been given to
such inter-dependencies and potential impacts on various standards which assume a BES
definition for their related requirements. 2. Wisconsin Electric participated in the June 26th
webinar and during the webinar it was stated that the PRC and CIP standards have unique and
unrelated BES bright line criteria. The final definition of BES must apply to all standards in a
clear and unambiguous manner. Under the CIP Version 5 standards, clarification is needed to
determine whether wind turbine controls become “Low Impact BES Cyber Systems” under the
bright line criteria. 3. Wisconsin Electric agrees with the NAGF comments to Question #6 Part
1. 4. Clarification should be provided that the BES definition pertains only to normal operating
conditions.
Individual
Melissa Kurtz
US Army Corps of Engineers
Agree
MRO NSRF
Individual
Daryl Hanson
Otter Tail Power Company
Agree
MIDWEST RELIABILITY ORGANIZATION NERC Standards Review Forum (NSRF)
Individual
David Jendras
Ameren
Yes
Yes
No
(1) We believe that the threshold of 30 kV is too low and needs to be raised to at least 70 kV
because subtransmission facilities are not intended to transfer power long distances and do
not respond to regional or interregional transfers. We believe that using a least common
denominator approach for voltage levels does not align with the intended use of the low
voltage networks in providing energy to firm loads throughout the Midwest. (2) At our
subtransmission facilities directional overcurrent relays are installed on all of the stepdown
transformers from the BES to limit the backfeed from the subtransmission system to the
transmission system. We request the SDT to consider a distribution factor or powerflow cutoff
in its discussions. We are not proposing significant contingency analyses be performed per the
TPL standards in order to qualify for the exclusion. However, the proposed threshold of 30 kV
without considering the network response, or magnitude of back-feed, or application of
directional overcurrent relays on non-BES transformers appears to us to be too simplistic and
arbitrary for this exclusion definition. (3) If multiple generating units connected at a common
point to the BES but less than 75 MW are determined to be non-BES, it would seem that the
low voltage networks and their supplies having a similar impact would also be determined to
be non-BES.
Yes
We request that the SDT renumber the Inclusions to yield I1 through I4 (i.e. move the I5
language to I4), as we believe this will be clearer than having a blank or unused I4.
Yes
Yes
The determination of BES facilities should be straight-forward and easy for both entities and
auditors to review and understand. We agree that, implementation of some bright-line
criteria to determine BES facilities are in the best interest of reliability. We encourage the SDT
to streamline the 78 page BES guidance document because we feel the process of
determining BES facilities is still not straight-forward.
Group
Southern California Edison
Marcus Lotto
No
SCE agrees with the deletion of the phrase “… or above 100 kV but…” from the Local network
(LN) exclusion language (E3). However, SCE believes that even with this change the E3
exclusion will be of little benefit in clarifying the issue FERC identified in Order 773-A. As
revised, the exclusion will still bring into the scope of the BES definition facilities that have no
impact, and were never envisioned to be a part of the BES. Moving forward, SCE recommends
that the SDT consider revising the definition to remove the generation threshold from E3 a,
especially if it intends to keep the current E3 b “Power flows only into the LN” language the
same. With E3 b in-place, as currently written, it doesn’t matter how much generation is
located in a LN if the load is sufficiently large that there is no flow out of the LN to negatively
impact the BES. Another approach would be to revise E3 b by deleting the language “Power
flows only into the LN” language. FERC does not seem to be adverse to minimal power flowing
out of a LN: In Order 773A FERC declined to direct NERC to allow minimal flows up to a
100MVA limit to transfer out of an LN, but indicated that the Phase 2 project was a more
appropriate forum to pursue this matter further. The best option would be to combine the
two approaches outlined above. This would truly characterize LNs and clearly eliminate from
the exclusion those looped facilities which operate in parallel with the BES.
No
By revising E1 in this manner, the SDT eliminates the issue of identifying dispersed power
producing resources, but in-turn creates a more restrictive definition as it relates to the
“wires and lines” component of the definition. The SDT definition is too heavily reliant on
static Generator MVA thresholds, which should not be the major determining factor for
bringing LNs, and now Radial lines, into the BES definition. The original FERC directive in Order
Nos. 743 and743-A asked that the functional test be used in the determination as a first step
for BES determination, and should be incorporated in the procedures for inclusion of the LNs
into the BES. SCE’s position is that facilities operated in-parallel with BES should be considered
part of the BES regardless of voltage level. For the “wires and lines” side of the BES definition,
the “impact on the Bulk Power System, should be a determining factor for identifying these
LNs or Radial systems as BES, not the total amount of interconnected generation.
No
The alternative identified as “Note 2” in the proposed Phase 2 BES Definition gives
preferential treatment to contiguous looped facilities, which should be defined as LNs. The
rationale used to justify this particular exclusion should be modified and included in the BES
Guidance Document so that it can be applied to both the E1 and E3. With some minor
revisions, the E1 loop exclusion rationale could similarly be applied to LNs which connect to
multiple points, such as within substations with double breaker and breaker-and-a-half
configurations. Another alternative would be to identify LNs interconnected to the BES with
breaker-and-a-half configurations as radial systems, and be eligible for the E1 exclusion. In
addition, the 30kV looped facilities threshold identified for exempting looped radial facilities is
too low. This threshold has the potential to include facilities owned and operated by
transmission dependent utilities/ “Distribution Providers” into the scope of the BES definition.
Yes
SCE requests that NERC properly define “non-retail generation.” SCE’s understanding of the
term “non-retail generation” is to describe those generation facilities whose purpose is to
exclusively sell power into wholesale markets. This understanding would define CoGeneration facilities as “non-retail,” and therefore not counted in the 75 MVA aggregate
threshold amount. In addition, the 75 MVA aggregate thresholds defined by the gross
nameplate MVA rating of the generators would count generating facilities where the
generators individually and/or in aggregate meet the 75 MVA threshold but exports less than
75 MVA to the grid. The clarification of “non-retail” generation is important since summing-up
generators producing this power is a major factor for determining what “wires and lines”
meet/ don’t meet the E1 and E2 Exclusions.
Individual
Kathleen Goodman
ISO New England Inc.
Yes
Yes
No
The 30 kV limit in Note 2 for which an entity does not have to consider a loop between two
otherwise radial systems should be raised to 50 kV. There are numerous 34.5 kV and 46 kV
circuits used in distribution that would require review with the 30 kV limit. The review
required for those 34.5 or 46 kV circuits is not warranted.
Yes
Yes
No
Group
ACES Standards Collaborators
Jason Marshall
Yes
While we believe the concerns expressed by the FERC directive could have been handled
through the bulk electric system (BES) exception process, we agree that the proposed changes
do address the FERC directive. Most transmission above 100-kV that terminates into subtransmission below 100 kV should be treated as radial since its impacts on the BES, in most
cases, is negligible. Since the vast majority of networked facilities below 100 kV will not
ultimately be part of the BES, it would make more sense to use the BES exception process to
include those that do impact the BES rather than subject all instances to the more
complicated E3 exclusion.
Yes
The modifications appear to address the directive. It removes the possibility that the BES will
not be contiguous from a generator connected at 100 kV or higher and the rest of the BES
that is 100 kV or higher. Furthermore, it does not appear to draw in sub-transmission facilities
that are connected below 100 kV to generator facilities that are included by inclusions I2 and
I3. For example, a Blackstart Resource connected on a 69 kV line may be part of the BES but
the 69 kV facilities connecting the unit to the BES would not be. Assuming this is correct; we
agree the changes address the directive appropriately.
No
While we agree with the approach and thank the drafting team for their creativity in coming
up with the approach, we think it needs more refinement. There is a high level description in
the supporting documents of how this approach was arrived at. However, there is a dearth of
details. We think more details are necessary to agree to the appropriate voltage level cutoff.
For instance, 34.5 kV is a common distribution voltage that can be networked. It is hard to
fathom any networked 34.5 kV system could have a material impact on the BES because of its
relative high impedance. Thus, at a minimum, we suggest raising the cutoff to 35 kV to
address these situations. We also suggest supplying the detail data/reports that were used to
arrive at the 30 kV cutoff.
No
(1) While we are not opposed to combining I2 and I4, we think I4 provides additional clarity
and granularity. I4 collectively with the Phase 1: BES Definition Reference Document is very
clear that the collector system is not included in the BES. Exclusion of the collector system is
not clear from I2 particularly without a modified reference document. If the combination of I2
and I4 persists, we recommend that the reference document should clearly state that the
collector system is not included similarly to the current version. (2) We do not understand
why the question states that the changes address Commission concerns. The Commission was
very clear in approving I4. Paragraph 58 of Order 773-A states the “Commission … confirms its
finding that including I4 provides useful granularity in the bulk electric system definition.” By
combining I4 into I2, this granularity is removed.
Yes
(1) In general, these are clarifying changes and we are supportive of them. However, one
change is not a clarifying change but is in fact a substantive change. Changing “a monitored
Facility of a permanent Flowgate…” to “any part of a permanent Flowgate…” is not a clarifying
change but is in fact a substantive change. Consider that a Flowgate contains a monitored
facility and often a contingent Facility. The contingent Facility will now be included whereas it
was not previously included. In the end, these contingent Facilities probably will already be
included by the bright line 100 kV threshold as they are usually a larger facility than the
monitored facility. However, this should not be represented as a clarifying change. (2) “OR”
should be “or”.
Yes
Given that Facilities below 100 kV could be included in the definition of the BES by the BES
exception process, the drafting team should consider removing “of 100 kV or higher” from E1.
Any radial facility regardless of voltage class should be excluded. By removing the clause, we
think it will offer further support to exclude radial facilities below 100 kV that a requester may
attempt to add via the BES exception process. We understand the exclusion is intended to
apply to the bright line definition of 100 kV which offers further reason to remove the clause.
Because it can only ever apply to 100 kV or higher facilities, it is superfluous.
Individual
Randy MacDonald
NB Power Transmission
Agree
NPCC Reliability Standards Committee
Group
North American Generator Forum Standards Review Team
Patrick Brown
No
The change in question was evidently intended to cover the 34.5 kV interconnection systems
of wind farms, but it also pulls into the BES the 230 kV feeders supplying aux power for fossil
plants (compare Figs. E1-7 and E1-7a in the FERC order 773/773a-amended Guidance
Document). The HV-to-MV transformers for aux loads may be included as well (no per Fig. E17a, yes per SDT inputs in the 6/26/13 webinar if the transformers are of the 2 or 3-winding
type). It makes sense to include in-line components (i.e. the GSU-to- connection point
conductors), but there does not appear to be any justification for adding auxiliary
transformers and their HV feeders to the BES. These are in-house systems that have no
significance for the grid in general. The change to E3 should have been limited to wind farms.
No
See comments for Question 1
Yes
No
The equipment being included in compliance with NERC Standards should only be that
equipment carrying >75 MVA - the collector systems, GSU and Gen Tie, not the individual
turbines. Implementing standards at the individual wind turbine level (< 2MW in many cases)
does not improve reliability and only created additional workload for both the registered
entities and the regions. A 2 MW wind generator will neither have an impact due to the loss
of the generation nor start cascading outages due to a failure to trip a 600 volt machine. As a
point of reference, many large generating stations have station service loads of that
magnitude.
Yes
Yes
The language of the proposed BES definition is rather convoluted and is therefore difficult to
apply correctly without the Guidance Document. The FERC order 773/773a-amended
Guidance Document is not complete or final for the phase-2 BES definition, however. Its
exclusion E1 statement is that of phase-1, not phase-2, for example, and a disclaimer on p.1
states that “…this reference document is outdated. Revisions to the document will be
developed at a later date to conform to the definition being developed in Phase 2.” It appears
that the phase-2 BES definition is being rushed through the approval process, and it would be
preferable to take the time to compile a complete and consistent body of documentation
before putting the matter up for a vote.
Individual
Michael Moltane
ITC
Yes
Via the information disseminated by the SDT, it appears to us that the drafting team intended
the additions to E1 to essentially say that loops between radial systems at voltages over 30 kV
are BES and cannot be excluded through the application of E3b. This is an attempt at
establishing as much of a bright line as possible and is embodied in Note 2 under E1. We are
having trouble seeing this in the proposed standard language. Regardless, to meet this intent
the language in E1 needs to be cleaned up and E3b removed. Alternatively, another Inclusion
could be added to cover the above 30 kV networked facilities to meet this intent. Further, we
don’t agree with establishing a 30 kV bright line for parallel systems, as we envision this being
fought in the courts as an encroachment into distribution, and will get bogged down. Rather,
something that can be reasonably expected to be adopted now should be proposed so that
we can get clarity/alignment with the phase 1 effort and then come back for a phase 3 effort
to determine the best process for dealing the sub-100 kV networks. The reference to 30 kV
should be removed altogether and the PC recommendations for E3b should be adopted (The
PC recommendation follows): (Begin PC quote) ""Real power flows only in the LN from every
point of connection to the BES for the system as planned with all lines in service and also for
first contingency conditions as per TPL‐001‐2, Steady State & Stability Performance Planning
Events P0, P1, and P2, and the LN does not transfer energy originating outside the LN for
delivery through the LN to the BES."""""" (end of PC quote) Note that the first contingency
conditions referred to above must include contingencies of elements within the proposed
Local Network in addition to contingencies on the proposed BES. This should be explicitly
stated in the standard so there’s no confusion. Finally, TPL-001 indicates that it is the Planning
Coordinator and the Transmission Planner responsibilities to perform the studies. For the
purposes of application of the proposed exclusion E3b we recommend that one functional
entity be responsible for this determination (probably the Planning Coordinator).
Individual
Spencer Tacke
Modesto Irrigation District
No
There is no technical basis or study to support the change.
No
Yes
No
1. WECC studies have shown that there are thousands of MWs of wind and PV generating
plants currently on-line, and thousands of MWs under development, in the WECC system, of
20 MW and less capacity. Ignoring the impacts of these units on the BES would be a mistake,
as recent studies by the WECC MVWG (Modeling and Validation Work Group) have shown. 2.
The revisions have made the definition of the BES so complicated, that the definition is no
longer in a form that can be applied in a straight forward and reasonable manner. Also, there
are no technical justifications provided for some of the exclusion criteria (e.g, 75 MVA and
300 kV values).
Individual
Don Streebel
Idaho Power Company
Yes
We agree that making the changes that are the subject of Q1 meets the Commission's
directive to "modify the local network exclusion to remove the 100 kV minimum operating
voltage to allow systems that include one or more looped configurations connected below
100 kV to be eligible for the local network exclusion".
Yes
We agree that making the changes that are the subject of Q2 meets the Commission's
directive to "implement exclusion E1 (radial systems) and exclusion E3 (local networks) so that
they do not apply to generator interconnection facilities for bulk electric system generators
identified in inclusion I2".
Yes
Idaho Power System Protection group: Yes, we agree with the approach in general, but are
concerned with a 30kV cutoff. In our system, connections are made in our distribution load
service at 35kV. If we are interpreting the language correctly, an evaluation would be required
for all of our 35kV load service for any connections in that subsystem, which represents a
significant additional burden. Idaho Power System Planning group: We are in favor of adding
note 2 to Exclusion E1 of the BES definition. However, we would suggest rewording note 2 as
follows, while matching the simplicity of note 1 of Exclusion E1: "A tie operated at a voltage of
30 kV or less between radial systems does not affect this exclusion." We believe it is not the
intent to place the threshold of 30 kV or less on the contiguous loop that is created by adding
the tie between the two radial systems, but rather the intent is to place the threshold of 30
kV or less on the tie itself between the two radial systems.
Yes
What is lost in deleting I4 per se and rolling up "dispersed power producing resources" into I2
is the distinctive characteristic of dispersed power producing resources of "utilizing a system
designed primarily for aggregating capacity, connected at a common point ". Without making
this distinction, the "dispersed power producing resources" are just another generating
resource. Therefore, there is no need to add "dispersed power producing resources" to I2 if I4
is deleted per se as suggested. At the same time, if the distinctive characteristic of dispersed
power producing resources of "utilizing a system designed primarily for aggregating capacity,
connected at a common point " was also rolled up to I2, then why delete I4 at all? IF the
recommendation to delete I4 and modify I2 as presented in the Project 2010-17 draft 1 is the
decision of the Project Team, we would recommend further adding "utilizing a system
designed primarily for aggregating capacity, connected at a common point" to clarify
"dispersed power producing resources". In conclusion, we would not be in favor of making
the changes that are the subject of Q4.
Yes
We would be in favor of making the changes that are the subject of Q5.
Yes
Another issue that came up, relative to Q4, is that even with the clarification of the "dispersed
power producing resources", the question remains as to how to treat new and existing, large
and small generator sources connected to feeders that connect to the same BES bus. Do we
need to keep a running total of the installed aggregated capacity and then, once the 75MVA
aggregate threshold is reached, change the BES classification of all these previously non-BES
units? It would be hard to argue that these are NOT “utilizing a system designed for
aggregating capacity”.
Individual
Edward O'Brien
Modesto Irrigation District
Agree
sacramento Municipal Utility District Balancing Area of Northern California
Individual
Tommy Drea
Dairyland Power Cooperative (DPC)
Agree
DPC supports comments submitted by the MRO NSRF.
Individual
Rich Salgo
NV Energy
Yes
Yes
Yes
While the details of the threshold voltage are still being ironed out, the concept of this note
acheives the objective of properly allowing for E1 exclusions in the presence of distribution
circuit loops or ties.
Yes
Yes, this was an efficient change to consolidate the two inclusions and in the long run, will
eliminate confusion and possible inconsistency.
Yes
No
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
However, ATC believes this would not include the significant network facilities below 100kV.
This would have to be addressed through a revision to the Inclusions.
Yes
However, ATC would like clarification on Blackstart resource paths that are operated at <
100kV. A Blackstart resource would be included in the BES per I3; however the path that is
less than 100kV would not be included in the BES.
No
ATC believes the 30kV threshold is too low and should be increased to at least 50kV.
Yes
ATC has no comments.
Yes
No comments.
Yes
Please clarify that E3b is to be applied for normal (intact) and emergency system conditions.
Rewording suggestion is as follows: E3b) Power flows only into the LN under normal and
emergency conditions and the LN does not transfer energy originating outside the LN for
delivery through the LN; Also ATC believes the SDT should include a note to define normal and
emergency conditions.
Individual
Tony Kroskey
Brazos Electric Power Cooperative
Agree
ACES Power Marketing
Group
Colorado Springs Utilities
Kaleb Brimhall
Yes
Yes
No
1.Can the standards drafting team clarify the reliability issue that they are trying to mitigate
with this language? What are we trying to prevent? 2.Why was the 30 kV threshold chosen as
opposed to any other voltage, what is the technical justification? a.Instead of a kV threshold
can we use a capacity rating, for example – use the 75 MVA rating used for collection point
asset inclusion? I know that there has been some discussion on this already, but we are not
convinced that 30kV is a sound threshold. 3.If we do decide to stay with a kV rating, then we
need to ensure that the “nominal voltage” is used as opposed to an “operating voltage.” This
is important to prevent a one-time operating voltage from drawings something in. 4.The
“notes” should be incorporated into the definition itself, not left as notes to create confusion
or additional need for clarification down the road.
Yes
1.Define “dispersed power producing resources."
Yes
Yes
1.We appreciate the clarifying language change of E3c. Monitoring status should not
necessarily include or exclude a Facility from the BES. We want to make sure that we do not
discourage or hamper monitoring of facilities by incorrectly involving Facilities that are
“monitored” but do not have an effect on the BES into this definition or other NERC
standards.
Group
Hydro One Networks Inc.
David Kiguel
No
Although the proposed change addresses the FERC directive, we do not agree with deleting
100 kV. Under the premise that the very first paragraph of the BES Definition already
establishes the bottom voltage threshold of 100 kV, its deletion may introduce ambiguity and
confusion. By definition and as per FERC Order 773 “the Commission stated that the core
definition also establishes a 100 kV criterion as a bright-line threshold” unless lower voltage
elements are included by the exception process and that distribution systems should not be
BES. Hence, we believe that, as the SDT correctly stated “above 100kV” in the currently
approved definition and E3 are consistent with the intent of BES definition. Finally, it is worth
noting that NERC is an international reliability standards setting organization and the BES
definition was also approved and/or accepted by the applicable governmental authorities in
other jurisdictions. Finally it is worth pointing that, in Order 773, the Commission further
stated that “the 100 kV threshold is a reasonable “first step or proxy” for determining which
facilities should be included in the bulk electric system. Indeed, it is reasonable to anticipate
that this threshold will remove from the bulk electric system the vast majority of facilities that
are used in local distribution, which tend to be operated at lower, sub-100 kV voltages”
Yes
We agree that transmission element(s) and/or generation should not be excluded by
definition. However, it is important to clarify that such configurations can be excluded
through the exception process if and when they are not necessary for the operation of BES or
interconnected BES.
No
Exclusion E1 provides a floor (30 kV threshold) which an entity does not have to consider the
loop in its determination of a radial system. Data provided to the drafting team shows that
there are no transmission elements below 50 kV in Ontario (and Canada) and very few in the
30-59 kV range (1%) in the US. A sub-set of this 1% can be included as BES through the
exception process if deemed necessary for the operation of interconnected BES. The
demarcation point between transmission and distribution may be different in non FERC
jurisdictions, such as the Canadian provinces. Accordingly, we suggest that the 30 kV
threshold be adjusted to 50 kV for Ontario (and Canada), since legislation establishes 50 kV as
the technical boundary line between transmission and distribution. It would also alleviate any
“unintended consequences” in future standards development. For example, in Ontario,
legislation establishes 50 kV as the technical boundary line between transmission and
distribution. In establishing voltage thresholds, NERC needs to consider non-US legislated
demarcation points, and the standard development process must make allowances for such
regulatory and/or jurisdictional differences. The establishment of the voltage floor for the E1
exclusion is inconsistent with the language and structure of the legislative framework in
Ontario. Furthermore, we believe that the exception process is not appropriate to resolve the
jurisdictional issue of whether facilities are part of the BES or not. As such, Note 2 should be
modified to read as follows: “Note 2 – The presence of a contiguous loop, operated at a
voltage of 30 kV or less, between configurations being considered as radial systems, does not
affect this exclusion for US registered entities. For a non-US Registered Entity, the voltage
level should be implemented in a manner that is consistent with the demarcation points
within their respective regulatory framework.
No
The combination of I2 with I4 is not as a result of FERC’s directive and/or clearly stated in the
scope of the Phase 2 SAR. In Order 773, Commission states: a) “Other than the directive to
modify exclusion E3 as discussed below, the Commission declines to direct NERC to further
modify the definition or the specified inclusions and exclusions” (Paragraph 52) b) the
Commission will not direct NERC to categorically include collector systems pursuant to
inclusion I4. (Paragraph 114) We believe that I2 and I4 wordings as approved by the
stakeholders, NERC BoT, FERC and applicable governmental authorities in Canada should be
retained. As such, we do not support this change to the definition because NERC should also
consider unintended consequences that could result out of this change. In our opinion, I4 is
meant for renewable energy resources (in particular Wind). These resources are inherently
different from both the planning and the real time operations perspectives. This change will
essentially designate every element of a wind farm above 75 MVA to its interconnection as a
BES facility including the collector systems which may not be necessary. For example, this will
essentially mean that collector systems shall be required to comply with TPL standards
performance assessment and design.
Yes
Yes
We suggest NERC must ensure that: 1) any new or changes to standards as a result of FERC
directives that apply to load supply reliability and/or continuity be limited to the FERC
jurisdiction only. In Canada, local load reliability requirements are under the authority of local
regulators such as the Ontario Energy Board in the Province of Ontario. 2) An Implementation
Plan does not conflict with Ontario regulatory practice with respect to the effective date of
the standards. It is suggested that this conflict be removed by appending to the effective date
wording, after “applicable regulatory approval” in the Effective Dates Section of the
Implementation Plan, to the following effect: “, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.” Prior to the wording “In those
jurisdiction….”. The same changes should be made to the first sentence in the Effective Date
Section of the proposed Definition document. 3) In our opinion, SDT has correctly crafted the
language in E1 and E3 in the approved definition. However it seems that the BES exception
process has not been adequately communicated for “inclusion of facilities” that are not
captured by the definition but may be necessary for the BES operation. To address such FERC
concerns, NERC should take steps (e.g. directing Regions) to provide assurance to FERC that
the exception process will be administered in an effective way by NERC, Regions and the
Reliability Coordinators along with Facility Owners to include sub 100 kV system(s) that are a)
used for bulk power transfer (not a sink) across the BES from one area to the other or b) are
necessary for the operation of interconnected BES in a reliable manner or c) can have an
adverse impact on the interconnect BES.
Group
Transmission Access Policy Study Group
William Gallagher
Yes
Yes
TAPS supports the SDT’s general approach and language in Note 2 to Exclusion E1. In light of
FERC’s interpretation of “radial,” it is vital that a minimum threshold be added to Exclusion
E1; without such a threshold, many TAPS members would have to perform a more
burdensome E3 analysis, and likely go through the much more resource-intensive exceptions
process, for Elements that are clearly not necessary for the reliable operation of the grid. We
therefore strongly support the SDT’s proposal of a minimum threshold. TAPS does, however,
suggest that the threshold be 40 kV rather than 30 kV, because we believe that >100 kV
radials connected by a loop between 30 kV and 40 kV are highly unlikely to be necessary for
the reliable operation of the interconnected grid, and so 40 kV would be a more efficient
threshold than 30 kV; the rare case that should be part of the BES should be included through
the Exceptions process. We understand that the SDT has been assembling technical support
for a 30 kV proposal, and accordingly provide the following evidence in support of using 40 kV
instead. We propose 40 kV as being between the commonly-used voltages of 34.5 kV and 46
kV. Neither threshold (30 kV or 40 kV) will capture “all and only” those Elements that should
be part of the BES, because neither threshold is (or can be) sufficiently granular; instead, the
goal should be for E1 (and the rest of the core definition) to get as close as possible to the
appropriate end-state, in order to minimize the need for case-by-case Exceptions of either the
inclusion or exclusion variety. We understand that a primary reason behind the SDT’s use of
30 kV is the belief that in some portions of the continent, voltages as low as 34.5 kV are
monitored by entities that have the responsibility to monitor to ensure the reliable operation
of the interconnected transmission system. We do not know which entities the SDT is
referring to (presumably it does not include all entities, since DPs monitor all voltages), but
we note that RFC and MISO, whose overlapping footprints are a very significant area, monitor
down to 40 kV. This suggests that the people with responsibility and on-the-ground
experience in those regions believe that 40 kV is the threshold below which impacts can safely
be assumed to be minimal. Second, while the SDT has stated that it reads Order 773 as finding
that impedance alone is insufficient to demonstrate that looped or networked connections
operating below 100 kV should not be considered in the evaluation of Exclusion E1, it is surely
an important factor. The consideration of impedance supports a 40 kV threshold. The
impedance of a circuit is inversely proportional to the square of the voltage. The amount of
parallel flow is inversely proportional to the impedance of a circuit. Thus, other things being
equal, a 69 kV line carries 25% of the flow of a 138 kV line, and a 34.5 kV line carries 6.25% of
the flow of a 138 kV line. Taking into consideration other factors such as transformer
impedances (which are usually much greater than the impedances of the lines themselves)
and the size and spacing of conductors, TAPS members believe that the large majority of 3040 kV loops connecting >100 kV radials will carry less than 5% of the flow of a 138 kV line. For
purposes of Transmission Loading Relief in NERC and NAESB standards (IRO-006 and WEQ008, respectively), FERC has accepted a 5% transfer distribution factor as being insignificant. It
is therefore reasonable to allow >100 kV radials connected by a 34.5 kV loop to qualify for
Exclusion E1: any loop flow is more likely than not to be insignificant, and it is a waste of
resources to require all such systems to assess their eligibility for Exclusion E3 or go through
the exceptions process. Instead, if there are isolated cases of such configurations that should
be included in the BES, they can be added through the inclusion Exceptions process. Most
TAPS members’ experience is that 34.5 kV lines tend to be used for local distribution, while 69
kV (and sometimes 46 kV) is used for subtransmission. The goal, ultimately, is to have the all
of the necessary Elements, and no unnecessary Elements, in the BES. We believe that using a
40 kV threshold will achieve that goal with fewer NERC, Regional Entity, and registered entity
resources than the 30 kV threshold proposed by the SDT.
An unintended consequence of the merging of I2 and I4 could be that dispersed behind-themeter retail customer generation, which itself is not BES under Exclusion E2, results in the
distribution system on which it is located being a BES collector system under I2. TAPS offers
three options to resolve this unintended consequence. The first option is to bring more of the
former I4 language into I2, e.g., “utilizing a system designed primarily for aggregating
capacity” to the inclusion, so that I2 would read: Generating resource(s), and dispersed power
producing resources utilizing a system designed primarily for aggregating capacity, including
the generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above with: a) Gross individual nameplate rating greater than 20 MVA,
OR, b) Gross plant/facility aggregate nameplate rating greater than 75 MVA. The second
option is to include the term “non-retail” after dispersed and before power producing. And
the third option is to clarify the use of the term “plant/facility” in b) such that it is clear that it
does not refer to all the retail back-up generators or net-metering power producing resources
connected to one distribution system connected to one connection to > 100 kV. TAPS also
notes that many reliability standards are not a good fit for small individual generating units at
dispersed, intermittent power resources such as wind farms; for example, given the frequency
with which wind turbines trip on and offline (as they are designed to do), tracking each
operation at each turbine to determine whether any misoperations have occurred would
extremely onerous and yield minimal reliability benefit. We acknowledge that this concern is
outside the scope of this project, but believe that the SDT should be aware of the issue as it
revises the BES definition.
Yes
Yes
TAPS applauds the SDT’s work to address FERC’s directives on a very accelerated timeline, as
well as the SDT’s hard work on this project over the last six years.
Individual
David Gordon
Massachusetts Municipal Wholesale Electric Company
Agree
American Public Power Association
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia
Power Company; Gulf Power Company; Mississippi Power Company; Southern Company
Generation; Southern Company Generation and Energy Marketing
Pamela Hunter
No
Southern agrees with NERC’s proposed removal of the phrase from the first sentence of
Exclusion E3 (Local Network Exclusion). However, the second sentence in Exclusion E3 also
appears to reference points of connection at 100kV or higher. Because the first sentence is
now modified to include transmission Elements operated below 100kV, the second sentence
should also be modified to remove the phrase “at 100kV or higher”. Therefore, the second
sentence should read: “LN’s emanate from multiple points of connection to improve the level
of service to retail customers and not to accommodate bulk power transfer across the
interconnected system.”
No
Southern recognizes and appreciates that the changes described in Question 2 respond simply
and concisely to FERC’s directive in Order 773 to implement exclusions E1(b) and (c) and E3(a)
so that the exclusions do not apply to tie-lines for generators identified in Inclusion I2. It
appears both from the revisions to Inclusion I2 and from FERC’s discussion in the orders that
FERC is intending to cover tie-lines to small-scale power generation technologies such as
wind, solar, geothermal, energy storage, etc. However, from reviewing the revised language
and the Bulk Electric System Guidance Document, it appears that one unintended
consequence of this directive (and NERC’s implementation of this directive) may be to pull
into the BES, for example, 230 kV or other high voltage feeders supplying auxiliary power to
conventional generation resources (i.e., not dispersed power producing resources). While it
may be appropriate to include certain components connecting the generation step-up units to
the connection point, Southern has not seen any technical justification for adding auxiliary
transformers and their high voltage feeders to the BES, which may have little to no
significance to the reliable operation of the interconnected BES. Southern suggests that the
SDT consider pursuing technical justification in Phase 2 or a later Phase for adding a note or
some more nuanced language in Exclusions E1 or E3 that would more accurately reflect the
distinctions described above by excluding from the BES these auxiliary elements while still
addressing the intent of FERC’s directive regarding dispersed power producing resources.
Yes
Southern generally agrees with the SDT’s approach in adding Note 2 to Exclusion E1 to
address FERC’s concerns regarding sub-100kV loops for radial systems. Respecting and
appreciating that the SDT may have intended to mirror not only the concept, but also the
language and format of Note 1 immediately above, Southern believes the language “does not
affect the exclusion”, by itself, can be confusing to entities trying to make applicability and
compliance determinations. To more directly and clearly articulate the concept of “not
affecting the exclusion” as meaning that the described configuration qualifies for the
exclusion and thus is excluded from the BES, Southern suggests the following revised Note 2
in quotes below. To the extent similar language can also be added to Note 1, Southern
believes that it would also benefit from the added clarity. “Note 2 – The presence of a
contiguous loop, operated at a voltage level of 30 kV or less, between configurations
otherwise being considered as radial systems, does not affect this exclusion from applying,
and thus such configurations should be eligible for Exclusion E1 and thus not included in the
BES.”
No
The equipment being included in compliance with NERC Standards should only be that
equipment carrying >75 MVA - the collector systems, GSU and Gen Tie, not the individual
turbines. Implementing standards at the individual wind turbine level (< 2MW in many cases)
does not improve reliability and only created additional workload for both the registered
entities and the regions.
Yes
Yes
The 2010-17 project webpage indicates that the Planning Committee’s March 2013 report
addresses the technical justification of threshold values, and that it will be updated by the
drafting team after the definition has been revised in Phase 2. In its comments submitted in
Project 2010-17 on February 2, 2012 (“Initial Comment Form”), Southern responded to two
questions posed by the SDT that asked about the propriety of pursuing technical justification,
but did not appear to be directly related to the threshold values. Southern includes those
responses here for the SDT’s convenience. First, in Question 3 of the Initial Comment Form,
the SDT asked whether it should pursue justification that supports the assumption that there
is a reliability benefit of a contiguous BES. In Order 773, FERC stated that “it is generally
appropriate to have the BES contiguous.” (P 167). To the extent that “contiguous” may be
considered synonymous with “interconnected”, Southern agrees that pursuing technical
justification to support such an assumption may be appropriate. Second, in Question 5 of the
Initial Comment Form, the SDT asked whether it should pursue technical justification to
support including an automatic interrupting device in Exclusions E1 and E3. It is not entirely
clear whether this was addressed by FERC in either Order 773 or Order 773-A. As Southern
stated in its February 12, 2012 comments, the scope of the term “automatic interrupting
device” is unclear and could benefit from some clarification by NERC. To the extent that the
term “automatic interrupting device” would constitute gas-operated breakers, as opposed to
relays, Southern would agree that such devices, to the extent they are associated with Radial
Systems qualifying under Exclusion E1 and Local Networks qualifying under Exclusion E3,
should also be excluded from the BES under those exceptions.
Individual
Scott Berry
Indiana Municipal Power Agency
Agree
Indiana Municipal Power Agency (IMPA) supports the comments submitted by the
Transmission Access Policy Study Group (TAPS). On question 3 on the Project 2010-17
comment sheet, IMPA agrees with the comments submitted by TAPS on this question and
firmly believes the threshold voltage should be 40kV for all of the reasons given in the answer
by TAPS. This is the main reason why IMPA voted negative on the ballot.
Individual
Brett Holland
Kansas City Power & Light
Agree
North American Generator Forum
Individual
Barry Lawson
National Rural Electric Cooperative Association
No
On page 2, last paragraph, of the Unofficial Comment Form the language regarding sub-100
kV loop analysis seems to indicate that the 30 kV level has already been determined and
selected through technical analysis. It is NRECA's understanding that such technical analysis
was not conducted prior to posting the phase 2 BES definition, and that such analysis is being
conducted now by a sub-group of the drafting team. NRECA requests that the drafting team
not focus on trying to specifically justify the 30kV bright-line, but instead, it should develop a
methodology/test to determine the highest reasonable voltage level that we should be using
for application of Exclusion E1. Such methodology/test should take into consideration the
issues FERC identified in Order Nos. 773 and 773-A regarding their concerns with sub-100 kV
looping facilities under Exclusion E1 and other comments from stakeholders that provide
technical support or justification for certain voltage levels for use in Exclusion E1.
Individual
Michael Goggin
American Wind Energy Association
Yes
Yes
Yes
No
AWEA is seriously concerned that taking the body of NERC reliability standards that now apply
to Bulk Electric System (BES) components and indiscriminately applying them to dispersed
power producing resources under the proposed Inclusions I2 and I4 will impose a major
burden and potentially result in significant confusion about the applicability of standards, with
little to no benefit for electric system reliability. These inclusions as currently drafted could
potentially even harm electric reliability by misallocating attention and resources away from
concerns that are far more likely to negatively affect BES reliability. AWEA strongly urges that
the BES definition be revised to only apply to the Point-of-Interconnection with the bulk
electric system, as that is the only place within the wind project where more than 75 MVA of
generating is aggregated and thus could reasonable affect BES reliability. In the alternative,
we ask that NERC revise Inclusion I2 as follows: I2 – Generating resource(s) [DELETE: and
dispersed power producing resources,] including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above with: a) Gross
individual nameplate rating greater than 20 MVA, OR, b) Gross plant/facility aggregate
nameplate rating greater than 75 MVA. [ADD: The application of individual NERC BES-relevant
standards to dispersed generation resources is to be specified in the applicability section of
individual standards.] The intent of this revision is to ensure that before BES-relevant
standards are applied to dispersed generators, each standard is evaluated to determine
whether it is reasonable to apply that standard to dispersed generators and whether applying
that specific standard to dispersed generators will significantly improve electric reliability.
Many NERC standards that apply to the BES were crafted before the significant growth of
dispersed generation and without dispersed generators in mind. Combined with the fact that
many dispersed generators are variable renewable resources that have limited capacity value
and are asynchronously connected to the power system, many NERC standards are likely to
have limited applicability or benefit if applied to dispersed generators. To our knowledge, a
compelling rationale has not been provided for why applying all NERC BES- relevant standards
to dispersed generators would significantly improve BES reliability. A blanket application of
NERC standards to dispersed generators by including them in the definition of BES would be
unduly burdensome, confusing, and provide little to no reliability benefit. As of the end of
2012, per AWEA’s Annual Market Report, there were approximately 45,100 utility-scale wind
turbines operating in the U.S., many of which are aggregated in wind projects that exceed 75
MVA in aggregate and are connected at a common point of voltage of 100 kV or above.
Including each of these wind turbines and their collector systems in the BES definition would
impose a large and undue burden on wind project owners and operators by potentially
forcing them to comply with a number of NERC compliance processes and reliability standards
that were crafted with large central-station generators in mind and cannot reasonably be
applied to each of the dispersed generators within a wind project. We do not believe that the
body of NERC requirements are adequately adapted to the technical differences of small,
aggregated generation units. For example, the administrative burden and cost of complying
with the GO/GOP standards at the individual generating unit level would be very substantial.
For standards such as PRC-005, R1, and R2, applying these standards to dispersed generators
would call for regular relay and protection system testing at numerous places within the wind
plant, potentially including the internal circuitry of each individual wind turbine. One wind
plant owner has indicated that, for one of its plants, applying the BES definition to the
individual dispersed generators would increase the number of elements subject to the PRC005 maintenance and testing requirements by more than a factor of 100. As another example,
TOP-002 R14 and TOP-003 R1 require status reporting of unplanned and planned generator
outages, respectively. We do not believe that the Balancing Authority (BA) or Transmission
Operator (TO) would benefit from being notified about the operational status of any single
dispersed generator at the typical wind turbine size of 2 MW or less. For the VAR series of
standards, small size voltage control and waveform stabilization circuitry could require
operational status monitoring and outage notification to the TO for this equipment. There are
many other examples of potential confusion or unnecessary work and cost that can arise from
the inclusion of small, individual dispersed generation assets, and their aggregation circuitry
and equipment, in the BES definition. Most importantly, no one has demonstrated that there
would be any material reliability benefit from applying all BES component standards to
individual dispersed generators. The nameplate capacity of an individual wind turbine
generator rarely exceeds 3 MW, and the average output of such a turbine is typically under 1
MW. Moreover, the capacity value contribution that grid operators typically assume for wind
projects for meeting peak electricity demand is typically less than 20% of the nameplate
capacity of the wind project. In the typical electrical layout of a wind plant, around a dozen
wind turbines are aggregated onto an electrical string of the collector array (which operates
at voltages well below 100kV), so even losing a single electrical string or even multiple
electrical strings will typically only result in the loss of a few dozen MW of generation at most.
Such minimal impacts fall well below the 75 MVA threshold that Inclusion 4 seeks to establish
for determining what should be included in the definition of the BES, as well as any
reasonable threshold for determining which electrical components are likely to cause a
reliability problem on the BES. In contrast, the electrical equipment at the Point-ofInterconnection (POI) with the BES (and not the individual generators and their collector
system), is a far more appropriate point for delineating between the BES and non-BES
electrical components and implementing a blanket application of NERC standards for BES
components, as the POI for a wind project comprised of more than 75 MVA of generation and
operating at more than 100 kV is the only part of the wind project that could reasonably
affect BES reliability. One of the only credible arguments for requiring that all BES reliability
standards apply to individual wind turbines is if one believed that wind turbines could be
potentially susceptible to a common mode failure that would cause a large number of the
generators within a wind plant to trip offline within a matter of seconds. Fortunately, all wind
turbines installed in the U.S. in recent years and going forward are already compliant with the
demanding voltage and frequency ride-through requirements of FERC Order 661A, which are
far more stringent than the ride-through requirements placed on other types of generation. In
the event of a system disturbance that causes a voltage or frequency deviation that would
affect all generators nearly simultaneously, a wind plant would be more likely to remain
online than almost all conventional generators, and the wind plant would likely only trip
offline if the power system had collapsed to the point that nearly all other generation had
already tripped offline. As a result, there is no compelling reliability reason for including
individual wind generators and their electrical collector systems in the BES definition.
Applying all BES-relevant standards to individual dispersed generators not only fails to
improve electric reliability, but it could even potentially harm electric reliability by
misallocating attention and resources away from concerns that are far more likely to
negatively affect BES reliability. Scarce resources exist for maintaining power system
reliability, and devoting resources and attention to an issue that is unlikely to affect BES
reliability can actually harm reliability by distracting attention from components that are more
likely to cause a reliability problem. Moreover, taking the whole body of standards that were
drafted with large central-station generators in mind and indiscriminately applying them to
dispersed generators with very different characteristics is likely to cause significant confusion,
further distracting from efforts that are important for maintaining and improving bulk power
system reliability. As a result, the BES definition should be revised as indicated above, to
ensure that before BES-relevant standards are applied to dispersed generators, each standard
is evaluated to determine whether it is reasonable to apply that standard to dispersed
generators and whether applying that specific standard to dispersed generators will
significantly improve electric reliability.
Yes
No
Individual
Luis Zaragoza
Tri-State Generation and Transmission, Inc.
Yes
Yes
Yes
Yes
Yes
Yes
Notwithstanding the NERC “Review of Bulk Electrical System Definition Thresholds” published
in March, 2013, Tri-State continues to believe that there is no reliability benefit to the BES by
having no minimum threshold for reactive devices on radial or non-radial systems. Two items
in particular give cause for concern about the recommended resolution in the review. First,
the review states that, since there is no clear technical justification for the threshold on
generator size, any basis for setting a threshold for reactive devices comparable to the BES
definition for generators does not have a technical basis. That is in itself a circular, nontechnical response, and not a technical reason for not having a threshold for the reactive
devices. The other argument that only 5% of the reactive devices would be excluded by using
a threshold also has no technical merit. Secondly, the review did not even attempt to analyze
what step voltage change a reactive device might have when it is in service. There are
multitudes of reasons why a reactive device might be placed at a location and its
unavailability may have a very small impact on the reliability of a system. Certainly it could
have much less impact on system, especially a radial system, than loss of a 20 MW generator
or a 75 MW aggregate plant would have. In addition, Tri-State believes that reactive devices
installed on radial systems are equivalent to reactive devices installed for the sole benefit of
retail customers (E4) and exclusion E1 should be added to the end of I5, i. e. “… excluded by
application of E1 or E4.” Tri-State also disagrees with the findings in the same review
regarding exclusions of Local Networks. Once again, the alleged lack of a technical basis for
BES generator size is used as rationale for not allowing any flow out of a Local Network in
Technical Alternative A. There is no technical merit to that argument. The argument for
disregarding Technical Alternative B also seems to have no technical basis. Tri-State continues
to believe that Local Networks could be excluded based on a minimum percentage of time
that real/reactive power may flow out of the network. An unintended consequence of not
allowing this to occur may be that entities will begin operating these systems radially to avoid
falling under the definition of the BES.
Group
US Bureau of Reclamation
Erika Doot
Yes
Yes
Yes
Yes
Reclamation agrees with the addition of the term "dispersed power resources" in I2.
However, Reclamation believes that certain aspects of Inclusion I2 are quite problematic. We
have included comments on outstanding issues in I2 related to generation step up
transformers (GSUs) in response to Question 6.
Yes
Yes
First, Reclamation suggests that the term “normally open” in E1 Note 1 is vague and should
include some type of threshold for what is “normally open” (e.g. 80% of annual operating
hours). The Bureau interprets "normally open" to mean under normal conditions rather than
under emergency or maintenance conditions. Reclamation believes clarification of the term is
necessary to make compliance obligations clear and avoid a variety of regional and entity
interpretations about which switches qualify as “normally open.” Second, Reclamation
believes that certain aspects of Inclusion I2 are quite problematic. Inclusion I2 implies that a
generation step-up transformer (GSU) is considered part of the generator in the BES
designation by stating that "[g]enerating resource(s) … including the generator terminals
through the high-side of the step up-transformer(s) connected at a voltage of 100 kV or
above…" are considered BES. However, this does not address situations where there is more
than one transformer before the transmission voltage. For example, a qualifying generator
may pass through multiple series transformers, of which only the last has terminals at 100kv
or above. The first transformer in the series would be considered the generator step uptransformer but not the other transformers in the series. Such series of transformers could
also involve sections of line which then raises the question of how they are classified. A
generator greater than 20 MW Generator could be stepped up to some under 100 kV voltage,
run some distance to a BES substation and then be transformed at that station to 100 kV or
greater voltage. It seems that this would be not deemed a Generation Resource under I2 and
would avoid needing to meet any requirements. Finally, in some instances, the Transmission
Owner may own, operate, and maintain GSUs. To address this lack of clarity, Reclamation
suggests that the drafting team revise the BES definition to better address GSUs in a separate
inclusion. In addition, if GSUs with only one terminal over 100kv are considered BES,
Reclamation questions why other transformers must have a "primary terminal and at least
one secondary terminal operated at 100kv or higher" to be considered BES resources. Third,
Reclamation suggests that NERC clarify the relationship between the new BES definition and
roles described in the functional model. The Functional Model does not address roles and
responsibilities related to transformers. In some instances, a Transmission Owner may own
GSUs and it is unclear whether the Generator Owner or Transmission Owner would have
compliance responsibility for the GSUs. Finally, Reclamation suggests that NERC define the
term "generation resources" to clarify which generator components are considered part of
"generation resources."
Individual
Alice Ireland
Xcel Energy
Yes
Yes
No
Xcel Energy asserts that the 30kV threshold proposed in Note 2 for Exclusion E1 is too low,
and instead proposes a 60kV threshold. Our extensive experience and expertise in performing
interconnected system modeling & operational analysis in three diverse Regions (MRO, SPP,
WECC) indicates that all three attributes comprising the technical justification used by the SDT
are always satisfied with the 60kV threshold. The recommended 60kV threshold recognizes
that 69kV is the lowest voltage at which loops between radial systems have the potential to
support adequate amount of power transfer under certain worst case scenarios and thus may
impact the >100kV system performance/reliability. In other words, Xcel Energy’s system
modeling & operational analysis experience indicates that 69kV is the lowest voltage at which
loops between radial systems present any possibility that any one of the three attributes in
the SDT’s technical justification may not be satisfied.
No
We do not agree that dispersed power resources should be treated the same at traditional
generators, as they are quite different in design and operation from traditional generators
and individually do not have the same impact on reliability. For the 2 main reasons detailed
below, we recommend that both I2 and I4 be retained, yet reworded such as this: “I2 –
Generating resource(s) and dispersed power producing resources, with gross individual
nameplate rating greater than 20 MVA, including the generator terminals through the highside of the generator step-up transformer(s) connected at a voltage of 100 kV or above.” “I4 –
For generating and dispersed power producing facilities with gross plant/facility aggregate
nameplate rating greater than 75 MVA, the bus where the aggregate generation is greater
than 75 MVA and continuing thru the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above. (Note: this does not include the individual generating resources
themselves, or the collector feeder system(s).)” 1) We are very concerned that the application
of NERC reliability standards to dispersed power producing resources under the proposed BES
Phase II definition will impose a major burden. The inclusions as currently drafted could even
harm electric reliability by misallocating resources away from reliability areas that are far
more likely to negatively affect BES reliability. As of the end of 2011, there were
approximately 38,000 utility-scale wind turbines operating in the U.S., many of which are
aggregated in wind projects that exceed 75 MVA in aggregate and are connected at a
common point of voltage of 100 kV or above. Including each of these wind turbines and their
collector systems in the BES definition would impose a large and undue burden on wind
project owners and operators, result in significant confusion about the applicability of
standards, and contribute no significant benefit to reliability. For example, the application of
PRC-005, R1, and R2 at the individual dispersed generator unit level would require regular
relay and protection system testing at numerous places within the wind plant, potentially
including the internal circuitry of each individual wind turbine. Specifically, the applicability
section 4.2.5.3 of PRC-005-2 implies that only the Protection System for the aggregating step
up transformer is included in scope, and that the Protection System for the individual
dispersed generators and aggregating systems are not. The current BES I2 includes both the
dispersed generators and the aggregating system for wind farms greater than 75 MVA,
applying PRC-005-2 requirements at 4.2.5.1 and 4.2.5.2 for generator trip relays, and
generator step-up transformers, respectively. We do not think that application of these test
requirements at the sub- 3MVA turbine level are the intent nor the reasonable scope of a
national reliability standard. We have similar concerns with other standards including PRC019-1, PRC-024-1, PRC-025-1, and PRC-027-1 and how application of these requirements
would conflict or confuse implementation of this Phase II definition as applied to distributed
generators and the associated aggregating systems. As another example, TOP-002 R14
requires status reporting of unplanned generator outages. We do not believe that the BA or
TOP would benefit from the operational notification status of any single dispersed generator
at the typical wind turbine size of 3 MVA or less. 2) A possible argument for requiring that all
GO/GOP reliability standards apply to individual wind turbines is if wind turbines were
susceptible to a common mode failure that would cause a large number of the generators
within a wind plant to trip offline within a matter of seconds. Fortunately, all wind turbines
installed in the U.S. in recent years and going forward comply with the demanding voltage
and frequency ride-through requirements of FERC Order 661A, which are far more stringent
than the ride-through requirements placed on other types of generation. In the event of a
system disturbance that causes a voltage or frequency deviation that would affect all
generators nearly simultaneously, a wind plant would be more likely to remain online than
almost all conventional generators, and the wind plant would likely only trip offline if the
power system had collapsed to the point that nearly all other generation had already tripped
offline. As a result, there is no compelling reliability reason for including individual wind
generators and their electrical collector systems in the BES definition.
Yes
Yes
As explained under question 4, we feel that dispersed power resources should not be treated
the same as traditional generating resources. However, if I2 moves forward as drafted, we
feel it is imperative to launch an effort similar to the GOTO/Project 2010-07, to modify and
add clarity to standards as they would apply to a dispersed power resource. This is important,
as many of the current GO/GOP standards would be difficult and impractical to apply to a
dispersed power resource. In addition, we recommend that interim compliance application
guidance be developed to help owners and operators of dispersed power resources
understand how to apply current standards, while also providing guidance to the auditors.
Individual
Nathan Mitchell
American Public Power Association
Yes
Yes
No
APPA appreciates the SDT efforts to set a non-zero threshold for exclusion E1 as proposed in
Note 2. However, the 30kV voltage threshold selected is too low and should be revised to
exclude the 34.5 kV voltage class. APPA believes including 34.5kV facilities will create a
significant compliance burden on registered entities, especially small entities. To set a
threshold this low will cast the compliance net onto radial facilities that perform distribution
functions that are not currently subject to NERC reliability standards because these facilities
are excluded as radials serving load. APPA believes that selecting the 30 kV threshold will
place an obligation on small entities to prove that power flows will not transfer through their
distribution systems for worst case scenarios. Without this change, APPA remains concerned
that addressing the 34.5 kV voltage class may overload the Rules of Procedure (ROP)
Exception Process. APPA recommends a higher threshold be studied and proposes 40 kV as an
alternative. In nearly all circumstances, the distribution factors on 34.5 kV circuits that
operate in normally closed configurations parallel to 115 kV and higher BES paths differ by 20-
to 1 or more, due to the combined impact of relative line voltage impedances, transformer
impedances, and longer line lengths on the lower voltage path(s) that loop through our load
centers and then connect back to the BES. Further, 34.5 kV circuits rarely affect SOLs or rated
paths. These circuits rarely form part of the interface between balancing areas. Exceptions to
the general rule that could have a significant impact on the BES should be addressed through
the Exception Process. APPA's comments to the Commission on BES Phase I Definition NOPR
September 4, 2012: Should the Commission in its final rule direct "other registered entities"
to conduct a study of all of their sub-100 kV facilities and state their potential impact to the
Regional Entity for evaluation for inclusion in the BES, then this directive would be excessively
burdensome to the industry, especially small registered entities. The Commission's proposal
would in effect require small registered entities (primarily Generator Owners and Distribution
Providers) to hire consultants to perform studies to assess the potential impact of large
numbers of non-BES facilities on the BES transmission network. APPA requests that in the
final rule the Commission give NERC and the Regional Entities the flexibility to develop, with
industry input, a reasonable approach for the evaluation of sub-100 kV facilities that does not
create an excessive burden on the industry, especially small entities. Adoption of the 40 kV
threshold would largely alleviate this potential burden.
Yes
Yes
No
Individual
Terry Harbour
MidAmerican Energy
Yes
Yes
MidAmerican would like clarification on Blackstart resources that are connected at < 100kV. A
Blackstart resource would be included in the BES per I3; however the path that is less than
100kV would not be included in the BES
No
MidAmerican believes the 30kV threshold is too low. MidAmerican believes that the SDT
should consider an “opt in” strategy for sub-100kV or Sub-60kV facilities rather than the
current proposed change which assumes facilities down to 34.5 kV are in NERC scope unless
entities “opt out” through the exemption process. Rather than include them in the BES
definition and require standard modifications to exclude them when it is not appropriate, it is
more efficient to modify those standards where their inclusion is determined to be
appropriate. This has already been done in some recently modified standards (e.g. the
generator verification standards now filed for regulatory approval, the modifications made to
standards for the generator interconnections).
No
In plants with an aggregate rating greater than 75 MVA, the individual generators should be
treated in the same manner as they would be in a stand-alone facility. If the individual
generator is at or below 20 MVA in a stand-alone facility it would not be included in the BES
and the owner of such a facility would not even have to register as a generator owner. That
same size generator in an aggregated facility should be treated the same and it should be
excluded from the BES. The portion of the facility at which the 75MVA or greater aggregation
occurs should be where the BES boundary occurs. Inclusion I2 has been modified to
incorporate I4 and I4 was eliminated. This is a good step, but the wording needs to be revised
to recognize the relative insignificance of the small generators to the bulk electric system.
There may be cases in some requirements of some standards where it is appropriate to
include generators below 20 MVA in those requirements. Rather than include them in the BES
definition and require standard modifications to exclude them when it is not appropriate, it is
more efficient to modify those standards where their inclusion is determined to be
appropriate. This has already been done in some recently modified standards (e.g. the
generator verification standards now filed for regulatory approval, the modifications made to
standards for the generator interconnections). Here is the proposed markup: “I2 – Generating
resource(s) and dispersed power producing resources with: a) Gross individual nameplate
rating greater than 20 MVA, including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above, OR, b) Gross plant/facility
aggregate nameplate rating greater than 75 MVA, beginning at a bus where the aggregate
generation is greater than 75MVA and continuing thru the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above”
Yes
Yes
With E1 (and E3) the SDT has created and “opt-out” process instead of an “opt-in” process.
Only a small portion of networked facilities less than 100kV have a material impact on the
BES. A better approach would be to utilize the BES process for exceptions and include those
that have material impact to the BES. Needlessly processing these sub 100kV systems through
the burdensome exclusion process is not an effective use of resources.
Individual
Carter B. Edge
SERC Reliability Corporation
No Comment
No Comment
No Comment
The inclusion language uses the words "generator terminals". "Generator terminals" are not a
good demarcation point for defining a bright-line for the collector system that represents
faciltites that are necessary for reliable operationThese words will not be clear with some
power producing resources (wind, solar, low-head hydro, etc.). The SDT should review solar,
fuel cell and other DC technologies to clarify the term “generator terminals” as it relates these
types of generating resources. An alternative may be to define a proxy for generating
resource "generator terminals" (may be made up of multiple individual resources) by the
connection point below the step-up transformer where aggregate capacity exceeds the
individual unit registration threshold of 20MVA.
No Comment
No
Standards Announcement
Project 2010-17 Definition of the Bulk Electric System
Phase 2 | Draft 1
Initial Ballot Results
Now Available
An initial ballot for Phase 2 of the Definition of Bulk Electric System (DBES) concluded at 8 p.m.
Eastern on Friday, July 12, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results
for the initial ballot.
Approval
Quorum: 85.53%
Approval: 49.73%
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 definition. The definition will then proceed to an additional 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
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010 -17 Definition of BES - Phase 2
Password
Ballot Period: 7/3/2013 - 7/12/2013
Ballot Type: Initial
Log in
Total # Votes: 337
Register
Total Ballot Pool: 394
Quorum: 85.53 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
49.73 %
Vote:
Ballot Results: The standard will proceed to an additional ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
105
8
90
36
88
51
2
2
4
8
394
#
Votes
1
0.5
1
1
1
1
0.2
0.1
0.4
0.8
7
#
Votes
Fraction
41
1
32
14
31
19
2
0
1
6
147
Negative
Fraction
0.5
0.1
0.478
0.519
0.47
0.514
0.2
0
0.1
0.6
3.481
Abstain
No
# Votes Vote
41
4
35
13
35
18
0
1
3
2
152
0.5
0.4
0.522
0.481
0.53
0.486
0
0.1
0.3
0.2
3.519
11
2
9
3
7
6
0
0
0
0
38
12
1
14
6
15
8
0
1
0
0
57
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Member
Ballot
Eric Scott
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Negative
Negative
Negative
Negative
Abstain
Affirmative
Abstain
Negative
Comments
NERC Standards
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
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Iowa 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.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
El Paso Electric Company
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
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
MidAmerican Energy Co.
Minnesota Power, Inc.
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
New York State Electric & Gas Corp.
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Oncor Electric Delivery
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Kevin J Lyons
Joseph Turano Jr.
Chang G Choi
Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Michael S Crowley
Douglas E. Hils
Amber Anderson
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Bob Solomon
Ajay Garg
Martin Boisvert
Molly Devine
Negative
Negative
Affirmative
Michael Moltane
Negative
Jim D Cyrulewski
Walter Kenyon
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
John Chin
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Allan Long
Terry Harbour
Randi K. Nyholm
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Randy MacDonald
Negative
Bruce Metruck
Raymond P Kinney
Robert Thompson
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Jen Fiegel
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
NERC Standards
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
Orlando Utilities Commission
Otter Tail Power 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
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Alameda Municipal Power
Ameren Services
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Farmington
City of Palo Alto
City of Redding
City of Tallahassee
City of Ukiah
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
1
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
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
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Marie Knox
Alden Briggs
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Douglas Draeger
Mark Peters
Philip Huff
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
Adam M Weber
Thomas C Duffy
Steve Alexanderson
Andrew Gallo
Linda R Jacobson
Eric R Scott
Bill Hughes
Bill R Fowler
Colin Murphey
Charles Morgan
John Bee
Peter T Yost
Gerald G Farringer
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
NERC Standards
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
3
3
3
3
3
3
3
3
3
3
3
3
4
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
East Kentucky Power Coop.
El Paso Electric Company
Entergy
Fayetteville Public Works Commission
FirstEnergy Corp.
Flathead Electric Cooperative
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
KAMO Electric Cooperative
Kissimmee Utility Authority
Kootenai Electric Cooperative
Lakeland Electric
Lincoln Electric System
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
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
Southern California Edison Company
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.
Alabama Municipal Electric Authority
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Patrick Woods
Tracy Van Slyke
Joel T Plessinger
Allen R Wallace
Cindy E Stewart
John M Goroski
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Theodore J Hilmes
Gregory D Woessner
Dave Kahly
Mace D Hunter
Jason Fortik
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
Doug White
Skyler Wiegmann
Ramon J Barany
David McDowell
Donald Hargrove
David Burke
Ballard K Mutters
John H Hagen
Dan Zollner
Terry L Baker
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
Jeff L Neas
Mark Oens
David B Coher
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Raymond Phillips
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
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
Alliant Energy Corp. Services, Inc.
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
Buckeye Power, Inc.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Cowlitz County PUD
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
North Carolina Electric Membership Corp.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Black Hills Corp
Bonneville Power Administration
BP Wind Energy North America Inc
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Buckeye Power, Inc.
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
Cowlitz County PUD
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Kenneth Goldsmith
Ronnie Frizzell
Duane S Dahlquist
Manmohan K Sachdeva
Shamus J Gamache
Reza Ebrahimian
Nicholas Zettel
John Allen
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Margaret Powell
Negative
Tracy Goble
Rick Syring
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Negative
Barry R. Lawson
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Cecil Rhodes
Affirmative
John Lemire
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Affirmative
Negative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Todd Komplin
Brock Ondayko
Sam Dwyer
Scott Takinen
Brent R Carr
Matthew Pacobit
Clement Ma
George Tatar
Francis J. Halpin
Carla Holly
Shari Heino
Chifong Thomas
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Michael Shultz
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Robert Stevens
Tommy Drea
Alexander Eizans
Marcus Ellis
Mike Garton
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
NERC Standards
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
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
Duke Energy
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
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
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.
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Pacific Gas and Electric Company
PacifiCorp
Pattern Gulf Wind LLC
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 Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
APS
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
Dale Q Goodwine
Affirmative
Dana Showalter
Gustavo Estrada
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
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
Michelle R DAntuono
Bernard Johnson
Leo Staples
Mahmood Z. Safi
David Ramkalawan
Richard J. Padilla
Bonnie Marino-Blair
Grit Schmieder-Copeland
Annette M Bannon
Tim Kucey
Steven Grega
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
David Thompson
Mark Stein
Melissa Kurtz
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
Linda Horn
Scott E Johnson
Edward P. Cox
Randy A. Young
Keith Sugg
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
7
8
8
9
9
9
9
10
10
10
10
10
10
10
10
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
Florida Power & Light Co.
Great River Energy
Lincoln Electric System
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern California Power Agency
Northern Indiana Public Service Co.
Oklahoma Gas & Electric Services
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
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.
EnerVision, Inc.
Central Lincoln PUD
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
Richard L. Montgomery
Silvia P. Mitchell
Donna Stephenson
Eric Ruskamp
Brenda Hampton
Blair Mukanik
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Matthew Schull
Steve C Hill
Joseph O'Brien
Jerry Nottnagel
Kelly Cumiskey
Carol Ballantine
Ty Bettis
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
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Negative
Affirmative
Peter H Kinney
Affirmative
David Hathaway
David F Lemmons
Thomas Gianneschi
Thomas W Siegrist
Edward C Stein
Debra R Warner
Bruce Lovelin
Negative
Negative
Affirmative
Affirmative
Donald Nelson
Affirmative
Negative
Negative
Diane J. Barney
Negative
Thomas G. Dvorsky
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
NERC Standards
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=160788e8-8ca7-48d6-9558-2e12b3fedd37[7/15/2013 10:49:34 AM]
Consideration of Comments
Project 2010-17 Definition of Bulk Electric System
The Project 2010-17 Drafting Team thanks all commenters who submitted comments on Draft 1, Phase
2 of the Bulk Electric System definition. The definition was posted for a 45-day formal comment period
from May 29, 2013 through July 12, 2013. Stakeholders were asked to provide feedback on the
definition and associated documents through a special electronic comment form. There were 93 sets
of responses, including comments from approximately 225 different people from approximately 138
companies representing all 10 segments of the Industry Segments as shown in the table on the
following pages.
The SDT has made the following changes to the proposed definition due to industry comments;
•
•
•
•
•
•
•
•
•
I2 – Generating resource(s) and dispersed power producing resources, including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above with:
I2 a) - Gross individual nameplate rating greater than 20 MVA,. ORr,
I4 - Omitted. dDispersed power producing resources consisting of:
Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross
nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point
where those resources aggregate to greater than 75 MVA , connected atto a common point of
connection at a voltage of 100 kV or above.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less,
between configurations being considered as radial systems, does not affect this exclusion.
Exclusion E 3(b): Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN;
E4 - Reactive Power devices installed for the sole benefit of a retail customer(s).
Implementation Plan and effective date language - This definition shall become effective on the
first day of the second calendar quarter after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required the definition shall go into effect become effective on
the first day of the second calendar quarter after Board of Trustees adoption or as otherwise made
effective pursuant to the laws of applicable governmental authorities.
Minority concerns:
• Several commenters wanted the SDT to revise the applicability of current standards due to their
feeling that changes were required due to the new BES definition. The DBES SDT conducted a
•
•
review of applicability of Reliability Standards. The review consisted of the Reliability Standards
that are applicable to the Transmission Owners (TO), Generator Owners (GO), Transmission
Operators (TOP), and Generator Operators (GOP). The review was based on the premise that
the applicability of Reliability Standards is limited to BES Elements unless otherwise stated in
the ‘Applicability’ section of the standard or identified in the individual requirements. The
review was conducted to: (1) Assess the impact of the revised BES definition on the current
applicability of the subject Reliability Standards, and, (2) Identify areas where the applicability
could be improved from a clarity perspective and (3) Assess the proper application of BPS vs.
BES. The results of this analysis were forwarded to the NERC Standards Committee for
consideration: (1) The BES SDT found no issues that were identified as an immediate concern
based on the revised definition of the BES, therefore the BES SDT did not develop any
supporting draft SARs or potential redline changes; (2) The BES SDT identified several areas
where the clarity of the applicability could be improved. These issues were documented and
provided to the NERC SC with the expectation is that these issues would be added to the
‘Standards Issues Database’ for consideration by future SDTs. Additionally, the results of the
BPS vs. BES assessment were provided to the NERC SC, again with the expectation is that these
issues would be added to the ‘Standards Issues Database’ for consideration by future SDTs.
Several commenters attempted to re-open items that were decided and approved in Phase 1
and for which no changes are being made in Phase 2. The SDT notes that those issues raised
were previously decided by the Commission in its related Orders, and were not a topic for
reconsideration in Phase 2.
Several commenters raised concerns about the SDT treatment of the thresholds that reside
within the BES definition. The results of the NERC Planning Committee’s (PC) evaluation of the
various thresholds contained in the BES definition were presented to the SDT for consideration
in developing revisions to the definition in Phase 2. The PC determined that all thresholds
should remain at the status-quo. The SDT, based on the recommendations from the PC, has
opted to retain the original thresholds in the definition.
The SDT wishes to emphasize to commenters that the looping facilities that operate at voltages below
100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while
disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in
figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was
reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the
sub-100 kV elements comprising radial systems and local networks will not be included in the bulk
electric system, unless determined otherwise in the exception process.”
All comments submitted may be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
Consideration of Comments: Project 2010-17 | August 2, 2013
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 2010-17 | August 2, 2013
Index to Questions, Comments, and Responses
1.
The SDT has deleted the phrase “… or above 100 kV but…” from the local network exclusion
language (E3) in response to a FERC directive. Do you agree that the SDT has correctly addressed
this directive? If you do not agree that this change addresses the directive, or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ...................................................................................................... 17
2.
As identified in the FERC directive, the SDT has revised the local network (Exclusion E3) and
radial system (Exclusion E1) exclusions so that they do not allow for the utilization of these
exclusions for generation interconnection facilities that are used to interconnect BES generation
identified in the generation inclusion (Inclusion I2) with BES transmission elements. Do you agree
that the SDT has correctly addressed this directive? If you do not agree that this change
addresses the directive, or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments. ........................................... 32
3.
The SDT has proposed an equally effective and efficient alternative to the Commission’s sub-100
kV loop concerns for radial systems by the addition of Note 2 in Exclusion E1. Do you agree with
this approach? If you do not support this approach or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions and
rationale in your comments............................................................................................................ 49
4.
The SDT has revised the generation resources and dispersed power resources inclusions
(Inclusions I2 and I4) in response to industry comments and Commission concerns. Do you agree
with these changes? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ...................................................................................................................................... 74
5.
The SDT has made a number of clarifying changes to language in response to industry comments
as follows: (a) I1: Change ‘under’ to ‘by application of’; (b) I2: Split out the inclusion to clearly
show that it is an ‘or’ condition; (c) I5: Add ‘unless excluded by application of Exclusion E4’; (d)
E3: Change ‘… retail customer Load…’ to ‘retail customers’; (f) E3c: Change ‘… a monitored
Facility of a …’ to ‘… any part of a…’; (g) E4: Add the phrase ‘installed for the sole benefit of’. Do
you agree with these changes? If you do not support these changes or you agree in general but
feel that alternative language would be more appropriate, please provide specific suggestions
(using the letter of the change) in your comments. ..................................................................... 103
6.
Are there any other concerns with this definition that haven’t been covered in previous
questions and comments? ............................................................................................................ 110
Consideration of Comments: Project 2010-17 | August 2, 2013
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
Florida Municipal Power Agency
2
3
X
X
X
X
4
X
5
6
X
X
X
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
3
2.
Group
David Dockery
Additional Member
1. Central Electric Power Cooperative
FRCC
Associated Electric Cooperative, Inc. JRO00088
Additional Organization Region Segment Selection
SERC
1, 3
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
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
3.
Group
Additional Member
Guy Zito
3
4
5
6
Northeast Power Coordinating Council
Additional Organization
7
8
9
10
X
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
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.
Donald Weaver
New Brunswick System Operator
NPCC 2
7.
Kathleen Goodman
ISO - New England
NPCC 2
8.
Wayne Sipperly
New York Power Authority
NPCC 5
9.
Michael Lombardi
Northeast Power Coordinating Council
NPCC 10
10. Christina Koncz
PSEG Power LLC
NPCC 5
11. Helen Lainis
Independent Electricity System Operator
NPCC 2
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
20. Ben Wu
Orange and rockland Utilities
4.
Louis Slade
Group
2
NPCC 1
Dominion
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Michael Crowley
Electric Transmission
SERC
1, 3
2.
Craig Crider
Electric Transmission
SERC
1, 3
3.
David Roop
Electric Transmission
SERC
1, 3
Consideration of Comments: Project 2010-17 | August 2, 2013
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
John Loftis
Electric Transmission
SERC
1, 3
5.
George Wood
Electric Transmission
SERC
1, 3
6.
Nick Goerger
Electric Transmission
SERC
1, 3
7.
Carl Eng
Electric Transmission
SERC
1, 3
8.
William Bigdely
Electric Transmission
SERC
1, 3
9.
Jeff Bailey
Nuclear
NPCC 5
10. Chip Humphrey
F&H
RFC
5
11. Sean Iseminger
F&H
SERC
5
12. Louis Slade
NERC Compliance Policy SERC
1, 3, 5, 6
13. Connie Lowe
NERC Compliance Policy RFC
5, 6
14. Mike Garton
NERC Compliance Policy NPCC 5, 6
15. Randi Heise
NERC Compliance Policy MRO
5.
Russel Mountjoy
Group
Additional Member
3
4
5
6
7
8
9
10
6
MRO NERC Standards Review Forum (NSRF)
Additional Organization
X
X
X
X
X
X
X
X
X
Region Segment Selection
1.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
2.
Chuck Lawrence
American Transmission Co
MRO
1
3.
Dan Inman
Minnkota Power Coop
MRO
1, 3, 5, 6
4.
Dave Rudolph
Basin Electric Power Coop
MRO
1, 3, 5, 6
5.
Kayleigh Wilkerson Lincoln Electric System
MRO
1, 3, 5, 6
6.
Jodi Jensen
Western Area Power Administration
MRO
1, 6
7.
Joseph DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
8.
Ken Goldsmith
Alliant Energy
MRO
4
9.
Lee Kittleson
Otter Tail Power
MRO
1, 3, 5
10. Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5, 6
11. Marie Knox
Midcontinent Independent System Operator MRO
2
12. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
13. Scott Bos
Muscatine Power & Water
MRO
1, 3, 5, 6
14. Scott Nickels
Rochester Public Utilities
MRO
4
15. Terry Harbour
MidAmerican Energy Co.
MRO
1, 3, 5, 6
16. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
17. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
6.
Dennis Chastain
Group
2
Tennessee Valley Authority
Consideration of Comments: Project 2010-17 | August 2, 2013
X
X
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
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
7.
Group
Jim Kelley
Additional Member
SERC EC Planning Standards Subcommittee
Additional Organization
1. John Sullivan
Ameren Services Company
SERC
1
2. Edin Habibovic
Entergy Services
SERC
1
3. James Manning
NC Electric Membership Corporation SERC
1
4. Philip Kleckley
SC Electric & Gas Company
SERC
1
5. Shih-Min Hsu
Southern Company
SERC
1
6. Darrin Church
Tennessee Valley Authority
SERC
1
8.
Group
Michael Jones
Additional Member
1. Brian Shanahan
9.
National Grid
Additional Organization
X
X
Region Segment Selection
X
X
X
X
Region Segment Selection
National Grid (Niagara Mohawk) NPCC 1, 3
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
10.
Group
Additional Member
Robert Rhodes
SPP Standards Review Group
Additional Organization
1.
Mo Awad
Westar Energy
SPP
1, 3, 5, 6
2.
Clem Cassmeyer
Western Farmers Electric Cooperative
SPP
1, 3, 5
3.
Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
4.
Bo Jones
Westar Energy
SPP
1, 3, 5, 6
5.
Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
6.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
Consideration of Comments: Project 2010-17 | August 2, 2013
X
Region Segment Selection
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Stephen McGie
City of Coffeyville
SPP
NA
8.
Jason Shook
Representing East Texas Electric Cooperative SPP
NA
9.
Ashley Stringer
Oklahoma Municipal Power Authority
SPP
4
10. Don Taylor
Westar Energy
SPP
1, 3, 5, 6
11.
Mary Jo Cooper
Group
Additional Member
Cooper Compliance Corp
Additional Organization
CIty of Ukiah
WECC 3
2. Elizabeth Kirkley
City of Lodi
WECC 3
3. Douglas Drager
City of Alameda
WECC 3
4. Ken Dize
Salmon River Electric Co-opt WECC 3
5. Blaine Ladd
California Pacific Company
WECC 1, 3
6. Michael Knott
Granite State Electric
NPCC 3
7. Angela Kimmey
Pasadena Water and Power WECC 1, 3
8. Xavier Baldwin
Burbank Water and Power
Group
3
X
X
X
X
X
X
4
5
6
7
8
9
10
X
Region Segment Selection
1. Colin Murphy
12.
2
WECC 3, 5
Chang Choi
City of Tacoma
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Travis Metcalfe
Tacoma Public Utilities
WECC 3
2. Keith Morisette
Tacoma Public Utilities
WECC 4
3. Chris Mattson
Tacoma Power
WECC 5
4. Michael Hill
Tacoma Public Utilities
WECC 6
13.
Group
David Thorne
Pepco Holdings Inc & Affiliates
Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley
14.
Group
Delmarva Power & Light Co RFC
Kent Kujala
1, 3
DTE Electric
X
Additional Member Additional Organization Region Segment Selection
1. Dan Herring
RFC
3, 4, 5
2. Al Eizans
RFC
3, 4, 5
15.
Group
Joe Turano
Iberdrola USA
X
Additional Member Additional Organization Region Segment Selection
1. John Allen
Iberdrola USA
NPCC 1
2. Ray Kinney
NYSEG
NPCC 1
Consideration of Comments: Project 2010-17 | August 2, 2013
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
16.
Group
Greg Campoli
2
3
4
5
6
7
8
9
10
X
IRC Standards Review Committee
Additional Member Additional Organization Region Segment Selection
1. Terry Bilke
MISO
MRO
2
2. Al DiCaprio
PJM
RFC
2
3. Kathleen Goodman ISO-NE
NPCC
2
4. Matt Morais
ERCOT
ERCOT 2
5. Ali Miremadi
CAISO
WECC 2
6. Ben Li
IESO
NPCC
2
7. Charles Yeung
SPP
SPP
2
17.
Group
Brent Ingebrigtson
Additional Member
X
PPL NERC Registered Affiliates
Additional Organization
X
X
X
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. Ellizabeth Davis
PPL EnergyPlus, LLC
MRO
6
5.
NPCC 6
6.
SERC
6
7.
SPP
6
8.
RFC
6
9.
WECC 6
18.
Group
Additional Member
Jason Marshall
Additional Organization
Region Segment Selection
1. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
2. Mohan Sachdeva
Buckeye Power, Inc.
RFC
3, 4
3. Kevin Lyons
Central Iowa Power Cooperative
MRO
4. Scott Brame
North Carolina Electric Membership Corporation SERC
5. Shari Heino
Brazos Electric Power Cooperative, Inc.
ERCOT 1, 5
6. Laurel Heacock
Oglethorpe Power Corporation
SERC
7. Mark Ringhausen
Old Dominion Electric Cooperative
19.
Group
Patrick Brown
X
ACES Standards Collaborators
RFC
1, 3, 4, 5
3, 4
North American Generator Forum
Standards Review Team
Consideration of Comments: Project 2010-17 | August 2, 2013
X
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional Member
Additional Organization
3
4
5
6
7
8
9
10
Region Segment Selection
1.
Allen Schriver
NextEra Energy
5
2.
Steve Berger
PPL Susquehanna, LLC
5
3.
Joe Crispino
PSEG Fossil, LLC
5
4.
Pamela Dautel
IPR-GDF Suez Generation NA
5
5.
Dan Duff
Liberty Electric Power
5
6.
Mikhail Falkovich
PSEG
5
7.
Don Lock
PPL Generation, LLC
5
8.
Joe O'Brien
NIPSCO
5
9.
Dana Showalter
E.ON
5
10. William Shultz
Southern Company
5
11. Mark Young
Tenaska, Inc
5
20.
David Kiguel
Group
2
Hydro One Networks Inc.
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David Curtis
Hydro One Networks Inc. NPCC 1, 3
2. Oded Hubert
Hydro One Networks Inc. NPCC 1
3. Bing Young
Hydro One Networks Inc. NPCC 1, 3
21.
22.
23.
24.
25.
26.
27.
28.
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Janet Smith, Regulatory
Compliance Supervisor
Tim Reyher
Donald Brookhyser
Ryan Millard
Emily Pennel
Marcus Lotto
Kaleb Brimhall
William Gallagher
Individual
Pamela Hunter
29.
Arizona Public Service Company
Northeast Utilities
Cogeneration Association of California
PacifiCorp
Southwest Power Pool Regional Entity
Southern California Edison
Colorado Springs Utilities
Transmission Access Policy Study Group
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Consideration of Comments: Project 2010-17 | August 2, 2013
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
50.
51.
52.
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Erika Doot
Tracy Richardson
Dennis Schmidt
Steve Alexanderson
Doug Hohlbaugh
PHAN, Si Truc
Grit SchmiederCopeland
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Thomas Breene
Brian J. Murphy
Bob Thomas
Jack Stamper
John Seelke
John Bee
Bret Galbraith
Jim Cyrulewski
Nazra Gladu
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Kenn Backholm
Joe Tarantino
Kayleigh Wilkerson
Daniela Hammons
RoLynda Shumpert
Roger Dufresne
David Burke
Southern Company Generation; Southern
Company Generation and Energy Marketing
US Bureau of Reclamation
Spirngfield Utility Board
City of Anaheim
Central Lincoln
FirstEnergy
Hydro-Quebec TransEnergie
2
3
X
X
X
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
Pattern Gulf Wind LLC
Wisconsin Public Service / Upper Peninsula
Power
NextEra Energy
Illinois Municipal Electric Agency
Clark Public Utilities
Public Service Enterprise Group
Exelon and its Affiliates
Seminole Electric
JDRJC Associates LLC
Manitoba Hydro
Public Utility District No.1 of Snohomish
County
Sacramento Municipal Utility District
Lincoln Electric System
CenterPoint Energy
South Carolina Electric and Gas
Hydro-Québec Production
Orange and Rockland Utilities Inc.
Consideration of Comments: Project 2010-17 | August 2, 2013
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
X
X
X
X
X
X
X
X
X
X
X
X
12
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
64.
65.
66.
67.
68.
69.
70.
71.
72.
73.
74.
75.
76.
77.
78.
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Don Jones
Marie Knox
Saul Rojas
Joylyn Faust
Michelle D'Antuono
Herb Schrayshuen
Donald Weaver
Randi Nyholm
Daniel Duff
Thomas Foltz
Mike Hirst
Kenneth A Goldsmith
Jason Snodgrass
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Diane J. Barney
Michael Falvo
Michael Lowman
Jim Thate
Barbara Kedrowski
Melissa Kurtz
Daryl Hanson
David Jendras
Kathleen Goodman
Randy MacDonald
Michael Moltane
Spencer Tacke
Don Streebel
Texas Reliability Entity
MISO
New York Power Authority
Consumers Energy Company
Occidental Energy Ventures Corp.
Self
New Brunswick System Operator
Minnesota Power
Liberty Electric Power LLC
American Electric Power
Cogentrix Energy Power Management, LLC
Alliant Energy
Georgia Transmission Corporation
New York State Department of Public
Service
Independent Electricity System Operator
Duke Energy
Delta-Montrose Electric Association
Wisconsin Electric
US Army Corps of Engineers
Otter Tail Power Company
Ameren
ISO New England Inc.
NB Power Transmission
ITC
Modesto Irrigation District
Idaho Power Company
Consideration of Comments: Project 2010-17 | August 2, 2013
2
3
4
5
6
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
X
X
X
X
X
X
X
X
X
13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
79.
80.
81.
82.
83.
Individual
Individual
Individual
Individual
Individual
84.
Individual
85. Individual
86. Individual
87.
88.
89.
90.
91.
92.
93.
Individual
Individual
Individual
Individual
Individual
Individual
Individual
Edward O'Brien
Tommy Drea
Rich Salgo
Andrew Z. Pusztai
Tony Kroskey
David Gordon
Scott Berry
Brett Holland
Barry Lawson
Michael Goggin
Luis Zaragoza
Alice Ireland
Nathan Mitchell
Terry Harbour
Carter B. Edge
Modesto Irrigation District
Dairyland Power Cooperative (DPC)
NV Energy
American Transmission Company
Brazos Electric Power Cooperative
Massachusetts Municipal Wholesale Electric
Company
Indiana Municipal Power Agency
Kansas City Power & Light
National Rural Electric Cooperative
Association
American Wind Energy Association
Tri-State Generation and Transmission, Inc.
Xcel Energy
American Public Power Association
MidAmerican Energy
SERC Reliability Corporation
Consideration of Comments: Project 2010-17 | August 2, 2013
X
X
X
X
2
3
X
X
X
4
5
X
6
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
14
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).
Summary Consideration: The SDT will consider your comments as if they were filed separately when reviewing and responding to the
comments from the entities indicated.
Organization
Supporting Comments of “Entity Name”
Brazos Electric Power Cooperative
ACES Power Marketing
Massachusetts Municipal Wholesale
Electric Company
American Public Power Association
Springfield Utility Board
Liberty Electric Power LLC
Essential Power
Hydro-Quebec Production
Hydro-Quebec TransEnergie Division
Indiana Municipal Power Agency
Transmission Access Policy Study Group (TAPS).
On question 3 on the Project 2010-17 comment sheet, IMPA agrees with the comments
submitted by TAPS on this question and firmly believes the threshold voltage should be
40kV for all of the reasons given in the answer by TAPS. This is the main reason why
IMPA voted negative on the ballot.
Illinois Municipal Electric Agency
Transmission Access Policy Study Group
Florida Municipal Power Agency
MISO
ISO/RTO Council - Standards Review Committee
Consideration of Comments: Project 2010-17 | August 2, 2013
15
Organization
Supporting Comments of “Entity Name”
JDRJC Associates LLC
Minnesota Power
MRO NERC Standards Review Forum (NSRF)
Dairyland Power Cooperative (DPC)
Otter Tail Power Company
Lincoln Electric System
Alliant Energy
US Army Corps of Engineers
Kansas City Power & Light
North American Generator Forum
Cogentrix Energy Power Management LLC
New Brunswick System Operator
NPCC Reliability Standards Committee
NB Power Transmission
Modesto Irrigation District
Sacramento Municipal Utility District Balancing Area of Northern California
Clark Public Utilities
Snohomish County PUD
Seattle City Light
Consideration of Comments: Project 2010-17 | August 2, 2013
16
1. The SDT has deleted the phrase “… or above 100 kV but…” from the local network exclusion language (E3) in response to a FERC
directive. Do you agree that the SDT has correctly addressed this directive? If you do not agree that this change 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: A number of comments expressed opposition to the change directed by the Commission for the deletion of
“…or above 100 kV but…” from the Exclusion E3 language. The opposition was typically due to the perception that the deletion would
make it likely that facilities operated lower than 100 kV would be swept into the BES. This change does not result in the inclusion of sub100 kV elements in the BES. Sub-100 kV elements, if otherwise excluded from the BES, will not be brought into the BES by application of
this revised language. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s interpretation, does not
propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless determined otherwise in the exception
process.” This was reaffirmed by the Commission in Order 773A, paragraph 36 which states: “Moreover, as noted in the Final Rule, the
sub-100 kV elements comprising radial systems and local networks will not be included in the bulk electric system, unless determined
otherwise in the exception process.”
Comments were received suggesting that certain amounts of out-flow should be allowed to exist within the confines of the E3 exclusion.
The language to which these comments refer, the provision requiring that there be no out-flow from the candidate local network, was
industry, Board, and Commission-approved in Phase 1 and is not part of the Phase 2 scope of work; hence the SDT proposes no change
to the definition in this regard.
Several commenters suggested that the reference to the 100 kV threshold should be removed from the second sentence of Exclusion E3
in addition to its removal in the first sentence. The SDT has determined that it is necessary to retain the 100 kV threshold in the second
sentence in order to properly confine the bounds of the E3 exclusion.
Commenters raised concerns with the change made by the SDT to the Exclusion E3(c) criterion wherein “a monitored Facility of a
permanent Flowgate” was changed to “any part of a permanent Flowgate”. The SDT believes that the reliable operation of the
interconnected transmission system requires operator situational awareness of any and all parts of permanent flowgates in order to
adequately provide for reliable operation. Hence, the presence of any part of a flowgate should preclude the application of the E3
Exclusion. Accordingly, the SDT is making no changes to this revised language of Exclusion E3(c).
A comment was received that sought clarification about whether the power flow provision of Exclusion E3 (b) refers to real power only,
or whether it includes reactive power. The language of Exclusion E3 (b) regarding power flow direction has been intended to be specific
to real power, not reactive power. Pursuant to this comment, the SDT has revised the Exclusion E3 (b) language, adding the word “Real”
preceding “Power”. Exclusion E3 (b) now reads as follows:
Consideration of Comments: Project 2010-17 | August 2, 2013
17
Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through the LN;
Finally, comments were received questioning the threshold of 30 kV proposed in the new Note 2 for Exclusion E1. To address this issue,
the SDT has embarked upon technical analyses to examine the justification for the threshold, and has determined that 50 kV is the
technically justifiable voltage threshold. [Also see consideration of these comments in response to Question 3.]
Organization
Yes or No
Hydro One Networks Inc.
No
Question 1 Comment
Although the proposed change addresses the FERC directive, we do not agree with
deleting 100 kV. Under the premise that the very first paragraph of the BES
Definition already establishes the bottom voltage threshold of 100 kV, its deletion
may introduce ambiguity and confusion. By definition and as per FERC Order 773
“the Commission stated that the core definition also establishes a 100 kV criterion as
a bright-line threshold” unless lower voltage elements are included by the exception
process and that distribution systems should not be BES. Hence, we believe that, as
the SDT correctly stated “above 100kV” in the currently approved definition and E3
are consistent with the intent of BES definition.
Finally, it is worth noting that NERC is an international reliability standards setting
organization and the BES definition was also approved and/or accepted by the
applicable governmental authorities in other jurisdictions.
Finally it is worth pointing that, in Order 773, the Commission further stated that
“the 100 kV threshold is a reasonable “first step or proxy” for determining which
facilities should be included in the bulk electric system. Indeed, it is reasonable to
anticipate that this threshold will remove from the bulk electric system the vast
majority of facilities that are used in local distribution, which tend to be operated at
lower, sub-100 kV voltages”
Response: This change does not result in the inclusion of sub-100 kV elements in the BES. Sub-100 kV elements, if otherwise
excluded from the BES, will not be brought into the BES by application of this revised language. Order 773, paragraph 155 states:
“Thus, the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in
figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission
in Order 773A, paragraph 36 which states: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems
Consideration of Comments: Project 2010-17 | August 2, 2013
18
Organization
Yes or No
Question 1 Comment
and local networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
Occidental Energy Ventures Corp. No
Occidental Energy Ventures Corp. (on behalf of all Occidental NERC Registered
Entities) (“OEVC”) believes that the literal application of FERC’s directive creates
vulnerabilities that must be addressed. First, E3 as proposed will require that no
energy may flow out of the Local Network for any reason. This would include
Reactive Power which is essential to supporting local system voltage. It is not
inconceivable that entities will take steps to eliminate Reactive Power export in
order to avoid the costs of reliability compliance.
Similarly, there is no relief in exclusion E3 for the unintended outflow of energy
under multiple contingency conditions. Already in Orders 773 and 773-A, FERC has
taken a stance that there are no acceptable scenarios where an excluded Local
Network may do so. We believe this is unreasonable, adds excessive costs, and does
little to reduce Bulk Electric System risk. FERC’s very conservative “no-exceptions”
view will prevail by default if the drafting team does not provide the alternative
language in the guideline document - and shown below for reference:”Real power
flows only in the LN from every point of connection to the BES for the system as
planned with all lines in service and also for first contingency conditions as per TPL001-2, Steady State & Stability Performance Planning Events P0, P1, and P2, and the
LN does not transfer energy originating outside the LN for delivery through the LN to
the BES.”
Response: The language to which these comments refer, the provision requiring that there be no out-flow from the candidate local
network, was industry, Board, and Commission approved in Phase 1 and is not at issue in this Phase 2 posting; hence the SDT
proposes no change to the definition in this regard.
The language of Exclusion E3 (b) regarding power flow direction has been intended to be specific to real power, not reactive power.
Pursuant to this comment, the SDT has revised the Exclusion E3 (b) language, adding the word “Real” preceding “Power”. Exclusion
E3 (b) now reads as follows:
E3 (b): Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through
Consideration of Comments: Project 2010-17 | August 2, 2013
19
Organization
Yes or No
Question 1 Comment
the LN;
New York Power Authority
No
Removal of 100kv threshold from the first part of E3 but the 100kV reference
remains in the second part of the E3 exclusion which is inconsistent. It is unclear
what value the second sentence of the E3 exclusion provides and should be removed
from the E3 exclusion.
Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
No
Southern agrees with NERC’s proposed removal of the phrase from the first
sentence of Exclusion E3 (Local Network Exclusion). However, the second sentence
in Exclusion E3 also appears to reference points of connection at 100kV or higher.
Because the first sentence is now modified to include transmission Elements
operated below 100kV, the second sentence should also be modified to remove the
phrase “at 100kV or higher”. Therefore, the second sentence should read: “LN’s
emanate from multiple points of connection to improve the level of service to retail
customers and not to accommodate bulk power transfer across the interconnected
system.”
Response: The SDT has determined that it is necessary to retain the 100 kV threshold in the second sentence in order to properly
confine the bounds of the E3 exclusion. No change made.
Southern California Edison
No
SCE agrees with the deletion of the phrase “... or above 100 kV but...” from the Local
network (LN) exclusion language (E3). However, SCE believes that even with this
change the E3 exclusion will be of little benefit in clarifying the issue FERC identified
in Order 773-A. As revised, the exclusion will still bring into the scope of the BES
definition facilities that have no impact, and were never envisioned to be a part of
the BES. Moving forward, SCE recommends that the SDT consider revising the
definition to remove the generation threshold from E3 a, especially if it intends to
keep the current E3 b “Power flows only into the LN” language the same. With E3 b
in-place, as currently written, it doesn’t matter how much generation is located in a
LN if the load is sufficiently large that there is no flow out of the LN to negatively
impact the BES. Another approach would be to revise E3 b by deleting the language
Consideration of Comments: Project 2010-17 | August 2, 2013
20
Organization
Yes or No
Question 1 Comment
“Power flows only into the LN” language. FERC does not seem to be adverse to
minimal power flowing out of a LN: In Order 773A FERC declined to direct NERC to
allow minimal flows up to a 100MVA limit to transfer out of an LN, but indicated that
the Phase 2 project was a more appropriate forum to pursue this matter further. The
best option would be to combine the two approaches outlined above. This would
truly characterize LNs and clearly eliminate from the exclusion those looped facilities
which operate in parallel with the BES.
Response: While the SDT agrees that the generation size and the threshold for flow out of the candidates for local network
exclusion are somewhat related, the industry, Board, and the Commission accepted and approved these limitations for the E3
exclusion in Phase 1. In Phase 2, the SDT, as directed, sought the counsel of subject matter experts of the NERC Planning Committee
on these threshold issues, and the result of this inquiry was that the SDT adopted the status quo, leaving Exclusion E3 unchanged.
Accordingly, the SDT concludes that there is no justification for changing either the out-flow provision or the threshold for
connected generation in local networks.
North American Generator
Forum Standards Review Team
No
The change in question was evidently intended to cover the 34.5 kV interconnection
systems of wind farms, but it also pulls into the BES the 230 kV feeders supplying aux
power for fossil plants (compare Figs. E1-7 and E1-7a in the FERC order 773/773aamended Guidance Document). The HV-to-MV transformers for aux loads may be
included as well (no per Fig. E1-7a, yes per SDT inputs in the 6/26/13 webinar if the
transformers are of the 2 or 3-winding type). It makes sense to include in-line
components (i.e. the GSU-to- connection point conductors), but there does not
appear to be any justification for adding auxiliary transformers and their HV feeders
to the BES. These are in-house systems that have no significance for the grid in
general. The change to E3 should have been limited to wind farms.
PPL NERC Registered Affiliates
No
The change in the question was evidently intended to cover the 34.5 kV
interconnection systems of wind farms, but it also pulls into the BES the 230 kV
feeders supplying aux power for fossil plants (compare Figs. E1-7 and E1-7a in the
FERC order 773/773a-amended Guidance Document). The HV-to-MV transformers
for aux loads may be included as well (no per Fig. E1-7a, yes per SDT inputs in the
Consideration of Comments: Project 2010-17 | August 2, 2013
21
Organization
Yes or No
Question 1 Comment
6/26/13 webinar if the transformers are of the 2 or 3-winding type). It makes sense
to include in-line components (i.e. the GSU-to- connection point conductors), but
there does not appear to be any justification for adding auxiliary transformers and
their HV feeders to the BES. These are in-house systems that have no significance
for the grid in general. The change to E3 should have been limited to wind farms.
Wisconsin Electric
No
Wisconsin Electric agrees with the NAGF comments in response to Question 1.
Response: The change addressed in this question was not related to the delivery systems of wind farms. Rather, it was in response
to the Commission’s directive in Order 773, specifically in Paragraph 199 where the Commission states “Therefore, we direct NERC
to modify exclusion E3 to remove the 100 kV minimum operating voltage in the local network definition.” The SDT proposes no
change to the language of Exclusion E3.
Northeast Power Coordinating
Council
No
The Directive was addressed by the revision, but generally Exclusion E3 does not
recognize that regardless of how power gets to the load, it impacts the Bulk Electric
System. The term bulk power is used in the opening sentence of E3. A definition of
bulk power would lend credence and justification to E3, and the elimination of “or
above 100 kV but”.
The new Note 2 associated with Exclusion E1 and the changes to E3 have added
ambiguity that did not exist before. The base definition does not address sub 100kV
contiguous loops. The existing Inclusions do not include sub 100kV contiguous loops
either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1 still
applies. E3 explains how any sub 300kV contiguous loop could be excluded as a local
area network, but there is nothing in the definition that clearly states that
contiguous loops operated below 100kV are considered part of the BES unless
excluded by E3. The 100kv threshold has been removed from the first sentence of
E3, but it is inconsistent that the 100kV reference remains in the second part of the
E3 exclusion. It is unclear what value the second sentence of the E3 exclusion
provides, and its removal should be considered. Under the premise that the very
first paragraph of the BES Definition already establishes the bottom voltage
threshold of 100kv, we agree with removing the mention of the 100kV bottom
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 1 Comment
threshold in exclusion E3.
The version of exclusion E3 criterion (c) filed with FERC January 25, 2012 (RM12-6000) requires a “Local Network” not to contain a monitored facility of a permanent
Flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored facility in the ERCOT or Quebec
Interconnections, and is not a monitored facility included in an Interconnection
Reliability Operating Limit (IROL). The definition became more vague by changing
exclusion E3 criterion (c) from “a monitored Facility of a permanent Flowgate...” to
“any part of a permanent Flowgate...” and could allow for too broad a reading. The
original language from Phase 1 of the BES definition regarding exclusion E3 criterion
(c) provided more clarity and guidance on how to apply this exclusion. It is
recommended that the original language from Phase 1 of the BES definition be
reinstated. Facilities should be included in the BES only if the elements of the
Facility are transferring power (flow) through a Flowgate, transfer path, or IROL.
The Phase 1 BES definition was approved by NERC after positive industry acceptance
providing that Phase 2 would reconsider some of the thresholds proposed in Phase
1. The important 75MVA generation threshold limit was included. The FERC
requested changes now limit the possibilities for exclusion: 1) limitation on the
possibility of radial exclusion because of looping below 100 kV; 2) refusal of radial or
local exclusions when there is at least one generator above 20 MVA. Those
limitations for exclusion go in the opposite direction to what industry expected.
NERC must realize that the definition will be applied to entities not under FERC
jurisdiction. It is important that NERC consult Canadian jurisdictions about the BES
definition.
Response: With respect to providing a definition of “bulk power” as used in the opening sentence of Exclusion E3, this term is used
generically, and is only meant to provide a conceptual sense of the purpose and character of the facilities suitable for exclusion.
This terminology has not changed from the industry, Board, and Commission approved Phase 1 definition. The SDT has determined
that a definition of this term is not necessary to improve the clarity of Exclusion E3.
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 1 Comment
The SDT has determined that it is necessary to retain the 100 kV threshold in the second sentence in order to properly confine the
bounds of the E3 exclusion.
The SDT believes that the reliable operation of the interconnected transmission system requires operator situational awareness of any
and all parts of permanent flowgates in order to adequately provide for reliable operation. Hence, the presence of any part of a
flowgate should preclude the application of the E3 Exclusion. Accordingly, the SDT is making no changes to this revised language of
Exclusion E3(c).
The SDT understands that the changes ordered by the Commission place limitations on the exclusion beyond what was expected by
the industry; however, the SDT is bound by the directives of that Order and therefore recommends no change.
A Canadian entity and several observers have participated in the development of the BES Definition in both Phases. The SDT
believes it has given due consideration to the Canadian perspectives.
Self
No
The earlier version of exclusion E3 criterion requires a Local Network not to contain
a monitored facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection, or a comparable monitored
facility in the ERCOT or Quebec Interconnections, and is not a monitored facility
included in an IROL. The definition now is more vague. The original language was
better. Facilities should be included in the BES only if the elements of the Facility are
transferring significant amounts of power which would impact the reliability of the
BES.
National Grid
No
The version of exclusion E3 criterion (c) filed with FERC January 25, 2012 (RM12-6000) requires a “local network” not to contain a monitored facility of a permanent
flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored facility in the ERCOT or Quebec
Interconnections, and is not a monitored facility included in an Interconnection
Reliability Operating Limit (IROL). By changing exclusion E3 criterion (c) from “a
monitored Facility of a permanent Flowgate...” to “any part of a permanent
Flowgate...” the definition became vaguer and could allow for too broad of a
reading. The original language from Phase 1 of the BES definition regarding
exclusion E3 criterion (c) provided more clarity and guidance on how to apply this
Consideration of Comments: Project 2010-17 | August 2, 2013
24
Organization
Yes or No
Question 1 Comment
exclusion. It is recommended that the original language from Phase 1 of the BES
definition be re-instated. Facilities should be included only if the elements of the
Facility are transferring power (flow) through a flowgate, transfer path, or IROL.
Response: The SDT believes that the reliable operation of the interconnected transmission system requires operator situational
awareness of any and all parts of permanent flowgates in order to adequately provide for reliable operation. Hence, the presence
of any part of a flowgate should preclude the application of the E3 Exclusion. Accordingly, the SDT is making no changes to this
revised language of Exclusion E3(c).
Hydro-Quebec TransEnergie
No
The phase 1 BES definition was approved by NERC after a positive acceptation by
industry, providing that phase 2 would reconsider some of the thresholds proposed
in phase 1. Among the thresholds, the limit of 75 MVA was an important one. Now,
FERC request important changes that limit the possibility of exclusion : 1) limitation
on the possibility of radial exclusion because of looping below 100 kV; 2) refusal of
radial or local exclusions when there are at least one generator above 20 MVA.
Those limitations for exclusion go in the opposite direction to what industry
expected. In that sense, HQT doesn't approved those changes.
Moreover, it is not acceptable that those restrictions requested by FERC be imposed
to all non-FERC jurisdiction. It is important that NERC consult also the Canadian
jurisdictions about the BES definition.
Response: The SDT understands that the changes ordered by the Commission place limitations on the exclusion beyond what was
expected by the industry; however, the SDT is bound by the directives of that Order and therefore recommends no change.
Modesto Irrigation District
No
There is no technical basis or study to support the change.
IRC Standards Review Committee
No
We are unable to find the technical justification for removal of the 100kV threshold.
We are unable to support this until the technical basis is presented.
Response: The SDT is making this change pursuant to the Commission’s directives in Order 773, and therefore, a technical
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 1 Comment
justification is not applicable.
Northeast Utilities
No
While it is recognized that electrical systems operated below 100KV can be
configured such that they should require BES treatment (i.e. the 92 KV networked
system involved in the 2011 Southern California - Arizona outage), a 30KV threshold
is too low to significantly impact the reliable operation of the higher voltage
transmission system. We propose increasing this threshold to a voltage in the 4050KV range.
The new Note 2 associated with Exclusion E1 and the changes to E3 have added
ambiguity that did not exist before. The base definition does not address sub-100kV
contiguous loops. The existing Inclusions do not include sub 100kV contiguous loops
either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1 still
applies. E3 explains how any sub 30kV contiguous loop could be excluded as a local
area network, but there is nothing in the definition to clearly state that contiguous
loops operated below 100kV are considered part of the BES unless excluded by E3.
An additional Inclusion should be added that specifically includes “all contiguous
loop operated below 100kV that is not solely used for the distribute power to load
unless excluded by application of Exclusion E1 or E3.”
The proposed change to the E1 exclusion definition to add Note 2 will require an
examination of NU sub-transmission system connections (69KV in CT and 34KV in
NH) and their connections to the >100KV transmission systems. Elements >100KV
originally categorized as E1 or E3 may become BES inclusions if there is underlying
sub-transmission path. A cursory review determine no elements categorized as E1 in
CT would be changed; however, 16 of the 30 E1 elements in NH could become BES
due to 34KV paths.
Response: The 30 kV value in the first posting of Phase 2 was initially chosen based on a high-level evaluation and was inserted in
the definition to introduce the concepts to the industry and seek supported technical opinions from the industry. As the technical
justification has now been completed, a final value of 50 kV has been selected for inclusion in this current posting. The white paper
detailing the technical justification for this position has been posted as a supporting document.
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 1 Comment
This change does not result in the inclusion of sub-100 kV elements in the BES. Sub-100 kV elements, if otherwise excluded from the
BES, will not be brought into the BES by application of this revised language. Order 773, paragraph 155 states: “Thus, the
Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the
bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A,
paragraph 36 which states: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local
networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
The proposed threshold value of 30 kV, which has now been modified to 50 kV, for looped facilities, is a qualifier for how the 100 kV
and above facilities will be evaluated for potential exclusion. For example, whether the criteria of Exclusion E1 (radial system) would
be used for evaluation or if the looped facilities exceed the threshold value thus requiring evaluation under the criteria of Exclusion
E3 (local network).
Central Lincoln
Yes
Central Lincoln agrees the SDT has addressed the directive, but continues to believe
the conditions on outflow and through flow are excessively restrictive. Please see
further comments in the response to Question 6.
Sacramento Municipal Utility
District
Yes
SMUD agrees the SDT has addressed the Commission’s Directive. However, removal
of 100kv threshold from the first part of E3 but the 100kV reference remains in the
second part of the E3 exclusion which is inconsistent. It is unclear what value the
second sentence of the E3 exclusion provides and should be removed from the E3
exclusion.
Public Utility District No.1 of
Snohomish County
Yes
The Public Utility District No.1 of Snohomish County agrees the SDT has addressed
the directive, but continues to believe the conditions on outflow and through flow
are excessively restrictive. Please see further comments in the response to Question
6.
SPP Standards Review Group
Yes
Please see our comment in Question 6 regarding removal of the 100 kV limit?
Response: Thank you for your support and please see responses to comments for Q6.
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
American Transmission Company
Yes
Question 1 Comment
However, ATC believes this would not include the significant network facilities below
100kV. This would have to be addressed through a revision to the Inclusions.
Response: The elimination of the phrase “…or above 100 kV but…” does not cause the inclusion of any facilities below 100 kV. In the
event that there are significant network facilities operating below 100 kV, these can be examined for inclusion through the Exception
Process under the Rules of Procedure. No change made.
Dominion
Yes
However, please see our comments to remaining questions. .
Response: Thank you for your support and please see responses to remaining questions.
Independent Electricity System
Operator
Yes
Under the premise that the very first paragraph of the BES Definition already
establishes the bottom voltage threshold of 100kV, we agree with removing the
mention of the 100kV bottom threshold in exclusion E3.
Idaho Power Company
Yes
We agree that making the changes that are the subject of Q1 meets the
Commission's directive to "modify the local network exclusion to remove the 100 kV
minimum operating voltage to allow systems that include one or more looped
configurations connected below 100 kV to be eligible for the local network
exclusion".
ACES Standards Collaborators
Yes
While we believe the concerns expressed by the FERC directive could have been
handled through the bulk electric system (BES) exception process, we agree that the
proposed changes do address the FERC directive. Most transmission above 100-kV
that terminates into sub-transmission below 100 kV should be treated as radial since
its impacts on the BES, in most cases, is negligible. Since the vast majority of
networked facilities below 100 kV will not ultimately be part of the BES, it would
make more sense to use the BES exception process to include those that do impact
the BES rather than subject all instances to the more complicated E3 exclusion.
Associated Electric Cooperative,
Yes
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 1 Comment
Inc. - JRO00088
MRO NERC Standards Review
Forum (NSRF)
Yes
Tennessee Valley Authority
Yes
SERC EC Planning Standards
Subcommittee
Yes
Cooper Compliance Corp
Yes
City of Tacoma
Yes
Pepco Holdings Inc & Affiliates
Yes
DTE Electric
Yes
Iberdrola USA
Yes
Arizona Public Service Company
Yes
PacifiCorp
Yes
Southwest Power Pool Regional
Entity
Yes
Colorado Springs Utilities
Yes
Transmission Access Policy Study
Group
Yes
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
US Bureau of Reclamation
Yes
FirstEnergy
Yes
Wisconsin Public Service / Upper
Peninsula Power
Yes
Public Service Enterprise Group
Yes
Manitoba Hydro
Yes
South Carolina Electric and Gas
Yes
Question 1 Comment
Orange and Rockland Utilities Inc. Yes
American Electric Power
Yes
Duke Energy
Yes
Ameren
Yes
ISO New England Inc.
Yes
NV Energy
Yes
American Wind Energy
Association
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Consideration of Comments: Project 2010-17 | August 2, 2013
30
Organization
Yes or No
American Public Power
Association
Yes
MidAmerican Energy
Yes
Question 1 Comment
Response: Thank you for your support.
Consideration of Comments: Project 2010-17 | August 2, 2013
31
2. As identified in the FERC directive, the SDT has revised the local network (Exclusion E3) and radial system (Exclusion E1)
exclusions so that they do not allow for the utilization of these exclusions for generation interconnection facilities that are used
to interconnect BES generation identified in the generation inclusion (Inclusion I2) with BES transmission elements. Do you agree
that the SDT has correctly addressed this directive? If you do not agree that this change 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: Commenters identified that the language of Inclusion I2 does not distinguish between retail generation
and non-retail generation. As such, it was challenged that the current proposal for Exclusions E1 and E3 do not take into
consideration Exclusion E2 generation that would not be classified as BES generation. The Commission’s final rule identified the
requested changes should be applied to “bulk electric system generators” and additional clarity was requested. The SDT
determined that a change was not necessary. The SDT would like to highlight that Exclusion E2 generation units could not apply to
Exclusion E1b because Exclusion E1b applies to generating resource connections only and Exclusion E2 generation serves Load to
the retail customer. Additionally, Exclusion E1c specifically highlights and excludes Exclusion E2 generation with the words “…with
an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).” Exclusion E3 uses similar
wording to exclude Exclusion E2 generation.
Some commenters expressed the opinion that there was a redundancy introduced in Exclusions E1b, c, and E3a with the retention
of the greater than 75MVA threshold. The SDT disagrees because the 75 MVA threshold is required to accommodate situations
such as the existence of multiple 10 MVA nameplate units within the radial system or local network which could add up to greater
than 75 MVA.
Commenters sought to clarify the 75 MVA limits to connected generation in Exclusion E3 with respect to other non-BES generation
that may be connected to a sub-100 kV distribution system. Additionally, commenters identified concerns with respect to the fact
that the presence of any BES generation will disqualify the E3 exclusion. The SDT wants to make this point clear: the language
means that any BES generation within a local network would disqualify the entity from claiming the E3 exclusion; and any non-BES
generation (with the exception of any non-BES generation identified in Exclusion E2) which totals an aggregate greater than 75
MVA would also disqualify the entity from claiming the E3 exclusion.
The language for the generator interconnection facilities portion of Inclusion I2 is still not clear to some commenters. Commenters
identified the language is not concerning in a simple interconnection but the confusion/risk comes when there are multiple feeders
and transformations between the generating resource and the BES with respect to the literal interpretation involving the term
“step-up transformer(s)” in an arrangement that is also used to serve local Load. The SDT has determined that the best place to
clarify industry concerns on this matter is within the Reference Document. The SDT has specifically inserted an example of a
multiple transformation interconnection facility in the Reference Document that clarifies that if there is a transformer with a highside connection below 100 kV within the interconnection that is also used to deliver power to serve Load below 100 kV, then the
generation resource and interconnection facilities (i.e., transformer) is excluded from the BES. The SDT would also like to refer to
the Commission’s agreement with this distinction within Order 773, paragraph 92.
Organization
Yes or No
Texas Reliability Entity
No
Question 2 Comment
(1) The current draft appears to disallow E1 and E3 exclusions based on the presence
of retail generation (such as generation within industrial facilities) within a radial
system or local network. This is because the language of I2 does not distinguish
between retail generation and non-retail generation. We do not think the current
language reflects the intention of the drafting team.
(2) Consider the following situation: an industrial facility is connected to the BES at
one point with 100 MVA of retail generation connected at 138 kV that never
provides more than 25 MVA to the grid. That generation is identified in I2, but it is
excluded by E2, so it is not BES generation. However, the radial transmission
facilities do not qualify as a “radial system” because of the presence of “generation
resources [] identified in Inclusions I2 or I3.”
(3) This can be corrected by (a) referring to E2 in I2 (perhaps add to I2: “unless
excluded by application of Exclusion E2”) ; or (b) referring to “BES generation” in E1
and E3 rather than merely referring to “I2.”
Response: The SDT would like to highlight that Exclusion E2 generation units could not apply to Exclusion E1b because Exclusion E1b
applies to generating resource connections only and Exclusion E2 generation serves Load to the retail customer. Additionally,
Exclusion E1c specifically highlights and excludes Exclusion E2 generation with the words “…with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).” Exclusion E3 uses similar wording to exclude Exclusion E2
generation. No change made.
Associated Electric Cooperative,
Inc. - JRO00088
No
AECI suggests the SDT consider the following change for I2: REPLACE: “Generating
resource(s) and dispersed power producing resources,” WITH: “Generating
resource(s) and dispersed power producing resources connected at 100 kV and
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 2 Comment
above,” RATIONALE: Clarity of intent. Inclusion I2’s order and new separation of
wording, appears to make “the high-side of the step-up transformer(s) connected at
a voltage of 100 kV or above” stand autonomous. Because “step-up transformer” is
not defined in the NERC Glossary, AECI is deeply concerned that the current wording
can become twisted to instruct industry to first locate their Plants greater than 75
MVA and Units greater than 20 MVA, next locate all the transformers connecting
them to the core BES at a voltage of 100 kV or above, and finally include all the wires
"between," which is most all of the sub-transmission systems and including sub-subtransmission following FERC's most recent logic. The core BES definition’s “Unless
modified by the lists shown below”, will further support this reading and go against
what the BES Phase II SDT has been assuring industry, that primarily elements 100 kV
and above are part of the BES.
AECI expresses this further concern for SDT consideration: With E3 now excluding I2,
it appears to be in technical conflict with E2, where E3 for a potential LN but with
any interior unit greater than 20 MW yet continuously consuming All interior
generation and more (per E3b), cannot be excluded and yet E2 can. Why?
Response: The SDT has determined that the best place to clarify industry concerns on this matter is within the Reference
Document. The SDT has specifically inserted an example of a multiple transformation interconnection facility in the Reference
Document that clarifies that if there is a transformer with a high-side connection below 100 kV within the interconnection that is
also used to deliver power to serve Load below 100 kV, then the generation resource and interconnection facilities (i.e., transformer)
is excluded from the BES. The SDT would also like to refer to the Commission’s agreement with this distinction within Order 773,
paragraph 92. No change made.
This is because the Commission Order referred to BES generation and Exclusion E2 generation serves Load to the retail customer and
is not BES generation. No change made.
Occidental Energy Ventures
Corp.
No
Although OEVC believes the language changes for E1 and E3 adequately addresses
the FERC directive, some entities have expressed a need for clarity when considering
E1 and E3 for cogeneration that would normally be excluded by application of E2. As
OEVC understands the position of these entities, the logic of applying I2, then E2,
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 2 Comment
and finally E1 or E3 according to the hierarchy could include, then exclude, and then
re-include an industrial generator that would otherwise qualify for Exclusion E2.
OEVC understands from the Webinar that this is not the intent of the SDT and that
clarification will be made so that no one can misinterpret the SDT’s intent.
Also, the language in E3 might be interpreted to mean that ANY BES generation
within an LN would disqualify the entity from claiming the E3 exclusion. It would
seem that only the pathway from the BES generator to the BES should be included in
the BES to satisfy the FERC directive and that the remainder of the LN might still
qualify. (Perhaps this will be clarified in the Guidance Document).
Finally, it still seems unnecessary to limit non-retail generation within the LN to 75
MVA when FERC has now stated that power cannot flow out of the LN under any
conditions.
Response: Application of the definition can, at times, be a multiple step operation. However, if an entity applies the definition in the
hierarchical fashion as described in detail in the Reference Document, it will greatly diminish the steps involved and any possible
confusion. No change made.
The SDT wants to make this clear: the language means that any BES generation within a local network would disqualify the entity
from claiming the E3 exclusion; and any non-BES generation (with the exception of any non-BES generation identified in Exclusion
E2) which totals an aggregate greater than 75 MVA would also disqualify the entity from claiming the E3 exclusion.
The SDT disagrees as the 75 MVA threshold is required to accommodate situations such as the existence of multiple 10 MVA
nameplate units within the radial system or local network which could add up to a total greater than 75 MVA. No change made.
PacifiCorp
No
Although PacifiCorp believes that the SDT has addressed the FERC directive, the
directive in general allows for equivalent viable alternatives. PacifiCorp believes that
FERC’s directive is overreaching and fails to consider the already minimal upper limit
of 75 MVA (gross nameplate rating) established in Exclusion E1. A generating
resource’s registration status or BES status should not have a bearing as to whether
it must have a contiguous path to the BES. The previous limited upper limit of 75
MVA established a point at which the registered generator(s) would not interfere
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 2 Comment
with the reliable operation of the interconnected system in the event of a loss of the
< 75 MVA generator(s) or of the < 75 MVA generator’s(s’) ability to respond to the
loss of critical generation elsewhere in the system. In the relatively few situations in
which the registered generating resource is critical to the operation of the
interconnected system, the associated transmission could be included within the
scope of the BES through the approved exception process.
Response: The SDT is responding to the mandated Commission directive. If an entity feels that the Commission overreached, that
matter needs to be discussed between the entity and the Commission and is outside the scope of the SDT. No change made.
Southern California Edison
No
By revising E1 in this manner, the SDT eliminates the issue of identifying dispersed
power producing resources, but in-turn creates a more restrictive definition as it
relates to the “wires and lines” component of the definition. The SDT definition is
too heavily reliant on static Generator MVA thresholds, which should not be the
major determining factor for bringing LNs, and now Radial lines, into the BES
definition. The original FERC directive in Order Nos. 743 and743-A asked that the
functional test be used in the determination as a first step for BES determination,
and should be incorporated in the procedures for inclusion of the LNs into the BES.
SCE’s position is that facilities operated in-parallel with BES should be considered
part of the BES regardless of voltage level. For the “wires and lines” side of the BES
definition, the “impact on the Bulk Power System, should be a determining factor for
identifying these LNs or Radial systems as BES, not the total amount of
interconnected generation.
Response: With this change, the SDT is implementing the Commission’s directives in Order 773A to modify Exclusions E1 and E3 so
that they do not apply to generator interconnection facilities for BES generators identified in inclusion I2. Any sub-100kV facilities
that an entity feels are BES facilities that are not captured by the definition can be submitted as such through the exception process.
No change made.
Northeast Power Coordinating
Council
No
I2 does not include “non-retail” generation which is inconsistent with E1 and E3.
E1b, c, and E3a contain redundant statements regarding the 75MVA generator
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 2 Comment
threshold. These statements should be corrected for clarity and consistency.
For Simple E1 Radial System Exclusions--The Drafting Team application of this FERC
directive is clear for simple E1 Radial System Exclusions. Any tie-line connected
radially to the BES and operated at 100kV or above connecting I2 or I3 generation
(aggregating to more than 75MVA) is part of the BES. However, beyond this simple
configuration the application of the tie-line directive is less clear. For the More
Complex E1 Radial System Exclusions--More complex applications of the tie-line
directive under the proposed BES Definition are less clear. Consider that Inclusion I2
states the tie-line includes “... the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above...” It could be
argued that this was intended to apply to a short line or bus connection between the
generator and the generator step-up unit. But in reality it could be a long
connection. Regardless, a fault can occur on any length of line or bus. Application of
the tie-line directive is less clear when there are multiple feeders and
transformations between the generating resource and the BES which include sub100kV operating voltages. For example, a GT with a 13.8kV output feeds local
distribution. This local distribution is also served by a 69-to-13.8kV step-down
transformer that is fed by a 69kV sub-transmission feeder supplied by a 138-to-69kV
transformer connected to the BES by a 138kV feeder serving multiple step-down
transformers to load. This Radial System has only one connection to the BES at
138kV. What facilities are covered by the tie-line directive, either the entire path
from “... the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above” or only the portion of the 138kV feeder
from the high-side terminals of the 138-to-69kV step-down transformer to the BES?
For the E3 Local Network Exclusion--Applying the tie-line directive within a Local
Network could be problematic. The proposed wording introduces issues similar to
those involving Cranking Paths from Black Start units. Local Networks by the
definition “emanate from multiple points of connection at 100 kV or higher.”
Defining a single tie-line through the Local Network presents problems. Is the tie-line
the shortest path geographically or electrically? Does the tie-line directive suggest
Consideration of Comments: Project 2010-17 | August 2, 2013
37
Organization
Yes or No
Question 2 Comment
single or multiple paths to the BES? The CIP drafting team recognized this problem
and defined the path, eliminating Regional or Entity discretion and avoiding
substantial ambiguity and confusion. Following the CIP Drafting Team example,
suggest adding the following wording: Note 3: The BES tie-line is defined as the
portion of the single shortest contiguous path operated at 100kV or above from
the I2 or I3 resource to the BES. The Radial System or Local Network excluded must
be defined so that it does not include a BES tie-line. Portions of the tie-line path
operated below 100kV are not part of the BES. Application of this note does not
extend to tie-line facilities operated below the 100kV core definition.
Response: The Commission’s final rule identified the requested changes should be applied to “bulk electric system generators” and
additional clarity was requested. The SDT determined that a change was not necessary. The SDT would like to highlight that
Exclusion E2 generation units could not apply to Exclusion E1b because Exclusion E1b applies to generating resource connections
only and Exclusion E2 generation serves Load to the retail customer. Additionally, Exclusion E1c specifically highlights and excludes
Exclusion E2 generation with the words “…with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).” Likewise, Exclusion E3 uses similar wording to exclude Exclusion E2 generation. No change made.
The SDT disagrees as the 75 MVA threshold is required to accommodate situations such as the existence of multiple 10 MVA
nameplate units within the radial system or local network which could add up to greater than 75 MVA. No change made.
The SDT has determined that the best place to clarify industry concerns on this matter is within the Reference Document. The SDT
has specifically inserted an example of a multiple transformation interconnection facility in the Reference Document that clarifies
that if there is a transformer with a high-side connection below 100 kV within the interconnection that is also used to deliver power
to serve Load below 100 kV, then the generation resource and interconnection facilities (i.e., transformer) is excluded from the BES.
The SDT would also like to refer to the Commission’s agreement with this distinction within Order 773, paragraph 92. No change
made.
New York Power Authority
No
I2 is inconsistent with E1& E3 by not including “non-retail” generation.
E1b&c and E3a contain redundant statements regarding the 75MVA generator
threshold. These statements should be corrected for clarity and consistency.
Consideration of Comments: Project 2010-17 | August 2, 2013
38
Organization
Yes or No
Sacramento Municipal Utility
District
No
Question 2 Comment
I2 is inconsistent with E1& E3 by not including “non-retail” generation.
E1-b & c and E3-acontain redundant statements regarding the 75MVA generator
threshold. These statementsshould be corrected for clarity and consistency.
Response: The Commission’s final rule identified the requested changes should be applied to “bulk electric system generators” and
additional clarity was requested. The SDT determined that a change was not necessary. The SDT would like to highlight that
Exclusion E2 generation units could not apply to Exclusion E1b because Exclusion E1b applies to generating resource connections
only and Exclusion E2 generation serves Load to the retail customer. Additionally, Exclusion E1c specifically highlights and excludes
Exclusion E2 generation with the words “…with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).” Likewise, Exclusion E3 uses similar wording to exclude Exclusion E2 generation. No change made.
The SDT disagrees as the 75 MVA threshold is required to accommodate situations such as the existence of multiple 10 MVA
nameplate units within the radial system or local network which could add up to greater than 75 MVA. No change made.
Hydro-Quebec TransEnergie
No
Same comment as for question 1
PPL NERC Registered Affiliates
No
See comments above.
North American Generator
Forum Standards Review Team
No
See comments for Question 1
Response: Please see response to Q1.
Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
No
Southern recognizes and appreciates that the changes described in Question 2
respond simply and concisely to FERC’s directive in Order 773 to implement
exclusions E1(b) and (c) and E3(a) so that the exclusions do not apply to tie-lines for
generators identified in Inclusion I2. It appears both from the revisions to Inclusion
I2 and from FERC’s discussion in the orders that FERC is intending to cover tie-lines
to small-scale power generation technologies such as wind, solar, geothermal,
energy storage, etc. However, from reviewing the revised language and the Bulk
Electric System Guidance Document, it appears that one unintended consequence of
Consideration of Comments: Project 2010-17 | August 2, 2013
39
Organization
Yes or No
Question 2 Comment
this directive (and NERC’s implementation of this directive) may be to pull into the
BES, for example, 230 kV or other high voltage feeders supplying auxiliary power to
conventional generation resources (i.e., not dispersed power producing resources).
While it may be appropriate to include certain components connecting the
generation step-up units to the connection point, Southern has not seen any
technical justification for adding auxiliary transformers and their high voltage
feeders to the BES, which may have little to no significance to the reliable operation
of the interconnected BES. Southern suggests that the SDT consider pursuing
technical justification in Phase 2 or a later Phase for adding a note or some more
nuanced language in Exclusions E1 or E3 that would more accurately reflect the
distinctions described above by excluding from the BES these auxiliary elements
while still addressing the intent of FERC’s directive regarding dispersed power
producing resources.
Response: The SDT does not agree that the Commission’s Order is intended to cover only small scale power generation facilities.
And, lacking a specific example or configuration, the SDT does not understand why the commenter feels that this change has an
unintended consequence of pulling in auxiliary power resources. No change made.
City of Anaheim
No
This Question No. 2 has clearer language than the Exclusions E1 and E3 themselves
when it qualifies the interconnected generation as “BES generation.” As discussed
below, Exclusions E1 and E3 should be modified to make clear that non-BES
generation (i.e., any non-Inclusion I2/I3 generation that is connected to non-BES
facilities, including distribution facilities operated below 100 kV) does not disqualify
a registered entity from either Exclusion E1 or Exclusion E3. Exclusions E1 and E3
should clearly state that the 75 MVA limitation on generation resources contained in
Exclusions E1(c) for radial systems and E3(a) for local networks applies to generation
resources that are actually connected to the potentially excluded radial system or
local network. The 75 MVA limitation should not apply to non-BES generation that
may be connected to a sub-100 kV distribution system beyond the radial system or
local network. Anaheim believes that the Drafting Team may intend for the existing
(i.e., Phase 1) definition to be applied in this manner. For example, both the radial
Consideration of Comments: Project 2010-17 | August 2, 2013
40
Organization
Yes or No
Question 2 Comment
system and local network definitions refer to “contiguous transmission Elements,”
which do not include “distribution Elements.” A 75 MVA (or greater) generator
connected to a 69 kV local distribution Element is not contiguous to the BES, nor is it
connected to a transmission Element; therefore, such distribution system generation
should not preclude the radial system or local network from being excluded from the
BES. Anaheim’s proposed revisions to Exclusions E1 and E3 to address this issue are
provided below. To the extent that the Drafting Team already intends for the
existing (i.e., Phase 1) BES definition to be interpreted and applied as described in
these comments and that no further changes to the Exclusions are warranted, then
Anaheim requests that the Drafting Team confirm this in future guidance documents
or that the Drafting Team so specify in response to these comments.
Exclusion E1:E1 - Radial systems: A group of contiguous transmission Elements that
emanates from a single point of connection of 100 kV or higher and: a) Only serves
Load.b) Only includes generation resources, not identified in Inclusion I2 or I3, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).c)
Where the radial system both serves Load and includes generation resources, the
generation resources (i) are not identified in Inclusions I2 or I3 and (ii) have an
aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating) directly connected to the radial system. [Anaheim proposes no
changes to the remainder of Exclusion E1; for brevity, the remainder of this exclusion
has not been restated.]Exclusion E3:E3 - Local networks (LN): A group of contiguous
transmission Elements operated at less than 300 kV that distribute power to Load
rather than transfer bulk power across the interconnected system. LNs emanate
from multiple points of connection at 100 kV or higher to improve the level of
service to retail customs and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:a) Limits on
connected generation: The LN does not include generation resources identified in
Inclusions I2 or I3 and does not have an aggregate capacity of non-retail generation
greater than 75 MVA (gross nameplate rating) directly connected to the LN at a
voltage of 100 kV or above;[Anaheim proposes no changes to the remainder of
Consideration of Comments: Project 2010-17 | August 2, 2013
41
Organization
Yes or No
Question 2 Comment
Exclusion E3; for brevity, the remainder of this exclusion has not been restated.]
Response: The intent of the SDT is that non-BES generation (with the exception of any non-BES generation identified in Exclusion
E2) which totals an aggregate greater than 75 MVA would also disqualify the entity from claiming the E3 exclusion. Future revisions
of the Reference Document will include new diagrams for any changes introduced as a result of Phase 2 decisions. No change made.
Cooper Compliance Corp
No
We agree that the Exclusion E3 is correct providing Including I2 is modified. We
recommend that I2 is further clarified to include a more specific definition of a
Generator Interconnection Facility (Transmission Interface) and provide clarification
that the generation counted against the “aggregate capacity of non-retail less than
or equal to 75 MVA (gross nameplate rating)” that disqualifies the radial exclusion in
E1 or the local area network exclusion E3.
Regarding the Transmission Interface, FERC recommendations contained in Docket
No. RM12-16-000 define the Standards applicable to the Transmission Interface.
These Standards are FAC-001-1, FAC-003-3, PRC_004-2.1a, and PRC-005-1.1b. We
have identified a potential gap in which a generator is connected to a portion of a
115 kV line owned by a distribution provider prior to connecting to what otherwise
would be considered the BES. Absent the generator, the line would only be used to
serve load and would be excluded under E3. We recommend clarification that does
not require the distribution provider to register as a Transmission Owner and
Operator based on the small section of line used as part of the Transmission
Interface. Instead, we recommend that the distribution line also qualifies as a
generator interconnection facility and is part of the transmission interface to the
generator only.
The following are our recommended changes to Inclusion I2.Generating resource(s)
and dispersed power producing resources connected at voltage of 100kV or above,
including the Generator Interconnection Facilities with:a) Gross individual
nameplate rating greater than 20 MVA, OR, b) Gross plan/facility aggregate
nameplate rating greater than 75 MVA.The Generator Interconnection Facilities
include the generator terminals through the point of interconnection to the
Consideration of Comments: Project 2010-17 | August 2, 2013
42
Organization
Yes or No
Question 2 Comment
transmission elements that would otherwise be considered transmission elements
included within the definition of Bulk Electric System.
Regarding the clarification on what is counted towards the 75 MVA that disqualifies
the radial or local area network exclusions, we believe it is the drafting teams intent
that the count of generation is only to include generation that has been defined
within the Inclusions or through the exception process. However, we feel the actual
definition could be enhanced to provide this clarification.
In separate comments made by the City of Anaheim they propose the following
modifications to the definition, which we agree better defines this definition.
Exclusion E1: E1 - Radial systems: A group of contiguous transmission Elements that
emanates from a single point of connection of 100 kV or higher and satisfies one of
the following additional criteria: a)
The radial system only serves Load.b)
If the radial system includes only generation resources, the generation resources (i)
must not satisfy the criteria set forth in either Inclusion I2 or Inclusion I3 and (ii)
must not have an aggregate capacity of greater than 75 MVA (gross nameplate
rating) directly connected to the radial system at a voltage of 100 kV or above.c)
If the radial system both serves Load and includes generation resources, the
generation resources (i) must not satisfy the criteria set forth in either Inclusion I2 or
Inclusion I3 and (ii) must not have an aggregate capacity of greater than 75 MVA
(gross nameplate rating) of non-retail generation directly connected to the radial
system at a voltage of 100 kV or above. Exclusion E3: E3 - Local networks (LN): A
group of contiguous transmission Elements operated at less than 300 kV that
distribute power to Load rather than transfer bulk power across the interconnected
system. LNs emanate from multiple points of connection at 100 kV or higher to
improve the level of service to retail customs and not to accommodate bulk power
transfer across the interconnected system. The LN is characterized by all of the
following: a)
Limits on connected generation: The LN does not include
generation resources identified in Inclusions I2 or I3 and does not have an aggregate
capacity of more than 75 MVA (gross nameplate rating) of non-retail generation
directly connected to the LN at a voltage of 100 kV or above.b)
Power flows
Consideration of Comments: Project 2010-17 | August 2, 2013
43
Organization
Yes or No
Question 2 Comment
into the LN; it rarely, if ever, flows out. The LN does not transfer energy originating
outside of the LN for delivery through the LN.
Response: The Commission’s final rule identified the requested changes should be applied to “bulk electric system generators”. The
SDT would like to highlight that Exclusion E2 generation units could not apply to Exclusion E3 because Exclusion E2 generation serves
Load to the retail customer. No change made. Additionally, Exclusion E1c specifically highlights and excludes Exclusion E2
generation with the words “…with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate
rating).” Likewise, Exclusion E3 uses similar wording to exclude Exclusion E2 generation.
Registration issues and applicability issues of other standards are beyond the scope of the SDT. However, the BES SDT conducted a
review of applicability of Reliability Standards. The review consisted of the Reliability Standards that are applicable to the
Transmission Owners (TO), Generator Owners (GO), Transmission Operators (TOP) and the Generator Operators (GOP). The review
was based on the premise that the applicability of Reliability Standards is limited to BES Elements unless otherwise stated in the
‘Applicability’ section of the standard or identified in the individual requirements. The review was conducted to: 1. Assess the impact
of the revised BES definition on the current applicability of the subject Reliability Standards, and; 2. Identify areas where the
applicability could be improved from a clarity perspective and assessed the proper application of BPS vs. BES. The results of this
analysis were forwarded to the NERC Standards Committee for consideration: 1. The BES SDT found no issues that were identified as
an immediate concern based on the revised definition of the BES, therefore the BES SDT did not develop any supporting draft SARs
or potential redline changes. 2. The BES SDT identified several areas where the clarity of the applicability could be improved. These
issues were documented and provided to the NERC SC with the expectation is that these issues would be added to the ‘Standards
Issues Database’ for consideration by future SDTs. Additionally, the results of the BPS vs. BES assessment were provided to the NERC
SC, again with the expectation is that these issues would be added to the ‘Standards Issues Database’ for consideration by future
SDTs.
Orange and Rockland Utilities
Inc.
No
Modesto Irrigation District
No
We generally agree with the Guidance Document that was provided by NERC
Drafting Team. The document showed that if there are any I2 Elements within a local
network, the specific I2 Elements are deemed to be BES Elements, but the rest of the
local network would still be qualified as Exclusion E3.
Consideration of Comments: Project 2010-17 | August 2, 2013
44
Organization
Yes or No
Question 2 Comment
Response: In response to Commission directives, any Inclusion I2 Elements would prevent an entity from applying the E3 Exclusion.
American Transmission Company
Yes
However, ATC would like clarification on Blackstart resource paths that are operated
at < 100kV. A Blackstart resource would be included in the BES per I3; however the
path that is less than 100kV would not be included in the BES.
MidAmerican Energy
Yes
MidAmerican would like clarification on Blackstart resources that are connected at <
100kV. A Blackstart resource would be included in the BES per I3; however the path
that is less than 100kV would not be included in the BES
MRO NERC Standards Review
Forum (NSRF)
Yes
The NSRF would like clarification on Blackstart resources that are connected at <
100kV. A Blackstart resource would be included in the BES per I3; however the path
that is less than 100kV would not be included in the BES
Response: Your statement is correct.
Independent Electricity System
Operator
Yes
In general we agree with these changes and propose the following alternative
language for more clarity: ’Generating resource(s) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above, and dispersed power producing resources connected at a common point at
a voltage of 100 kV or above with;’
Response: The SDT has separated Inclusions I2 and I4 for the clarity the industry is seeking.
SPP Standards Review Group
Yes
Please see our comment in Question 6 regarding removal of the 100 kV limit?
Response: Thank you for your support and please see the response to Q6.
ACES Standards Collaborators
Yes
The modifications appear to address the directive. It removes the possibility that the
BES will not be contiguous from a generator connected at 100 kV or higher and the
rest of the BES that is 100 kV or higher. Furthermore, it does not appear to draw in
Consideration of Comments: Project 2010-17 | August 2, 2013
45
Organization
Yes or No
Question 2 Comment
sub-transmission facilities that are connected below 100 kV to generator facilities
that are included by inclusions I2 and I3. For example, a Blackstart Resource
connected on a 69 kV line may be part of the BES but the 69 kV facilities connecting
the unit to the BES would not be. Assuming this is correct; we agree the changes
address the directive appropriately.
Response: Thank you for your support.
Public Utility District No.1 of
Snohomish County
Yes
The Public Utility District No.1 of Snohomish County suggests increasing the 30kV
threshold to “35kV or less” as 34.5kV is a common distribution voltage used in rural
communities and should not be classified as BES. From Wikipedia “Rural
electrification systems, in contrast to urban systems, tend to use higher distribution
voltages because of the longer distances covered by distribution lines (see Rural
Electrification Administration). 7.2, 12.47, 25, and 34.5 kV distribution is common in
the United States...”
Response: The SDT has provided a white paper as supporting documentation for this posting that provides a detailed technical
analyses justifying a 50 kV threshold. [Also see consideration of these comments in response to Question 3.]
Idaho Power Company
Yes
We agree that making the changes that are the subject of Q2 meets the
Commission's directive to "implement exclusion E1 (radial systems) and exclusion E3
(local networks) so that they do not apply to generator interconnection facilities for
bulk electric system generators identified in inclusion I2".
Hydro One Networks Inc.
Yes
We agree that transmission element(s) and/or generation should not be excluded by
definition. However, it is important to clarify that such configurations can be
excluded through the exception process if and when they are not necessary for the
operation of BES or interconnected BES.
Dominion
Yes
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Tennessee Valley Authority
Yes
SERC EC Planning Standards
Subcommittee
Yes
City of Tacoma
Yes
Pepco Holdings Inc & Affiliates
Yes
DTE Electric
Yes
Iberdrola USA
Yes
Question 2 Comment
IRC Standards Review Committee Yes
Arizona Public Service Company
Yes
Southwest Power Pool Regional
Entity
Yes
Colorado Springs Utilities
Yes
US Bureau of Reclamation
Yes
Central Lincoln
Yes
FirstEnergy
Yes
Wisconsin Public Service / Upper
Peninsula Power
Yes
Public Service Enterprise Group
Yes
Consideration of Comments: Project 2010-17 | August 2, 2013
47
Organization
Yes or No
Manitoba Hydro
Yes
South Carolina Electric and Gas
Yes
Self
Yes
American Electric Power
Yes
Georgia Transmission
Corporation
Yes
Duke Energy
Yes
Ameren
Yes
ISO New England Inc.
Yes
NV Energy
Yes
American Wind Energy
Association
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
American Public Power
Association
Yes
Question 2 Comment
Response: Thank you for your support.
Consideration of Comments: Project 2010-17 | August 2, 2013
48
3. The SDT has proposed an equally effective and efficient alternative to the Commission’s sub-100 kV loop concerns for radial
systems by the addition of Note 2 in Exclusion E1. Do you agree with this approach? If you do not support this approach or you
agree in general but feel that alternative language would be more appropriate, please provide specific suggestions and rationale
in your comments.
Summary Consideration: A number of comments indicated that the 30 kV voltage shown in the initial posting was too low or did not
have a technical justification. The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition
to introduce the concept and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper that
is posted as a supporting document for the second posting of this project which provides an overview of the regional criteria and
contingency load flow analysis. The SDT has determined that 50 kV is a technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to insure that a clear bright-line is established.
Comments were received that indicated systems less than 100 kV would be included in the BES. The looping facilities that operate at
voltages below 100 kV are NOT included in the BES. Order No. 773, paragraph 155 states: “Thus, the Commission, while disagreeing
with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless
determined otherwise in the exception process.” This was reaffirmed by the Commission in Order No. 773A, paragraph 36:
“Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not be included in
the bulk electric system, unless determined otherwise in the exception process.”
Some comments concerned the wording or the use of Note 2. The SDT has considered these comments and has decided to leave the
format of Notes 1 and 2 as shown in the posting. Note 2 indicates that no loops below 50kV need to be considered when evaluating
radials. It should be noted that normally open switches at any voltage will not disqualify the use of Exclusion E1.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being considered as
radial systems, does not affect this exclusion.
Organization
Yes or No
Ameren
No
Question 3 Comment
(1) We believe that the threshold of 30 kV is too low and needs to be raised to at
least 70 kV because subtransmission facilities are not intended to transfer power
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 3 Comment
long distances and do not respond to regional or interregional transfers. We believe
that using a least common denominator approach for voltage levels does not align
with the intended use of the low voltage networks in providing energy to firm loads
throughout the Midwest.
(2) At our subtransmission facilities directional overcurrent relays are installed on all
of the stepdown transformers from the BES to limit the backfeed from the
subtransmission system to the transmission system. We request the SDT to consider
a distribution factor or powerflow cutoff in its discussions. We are not proposing
significant contingency analyses be performed per the TPL standards in order to
qualify for the exclusion. However, the proposed threshold of 30 kV without
considering the network response, or magnitude of back-feed, or application of
directional overcurrent relays on non-BES transformers appears to us to be too
simplistic and arbitrary for this exclusion definition.
(3) If multiple generating units connected at a common point to the BES but less
than 75 MW are determined to be non-BES, it would seem that the low voltage
networks and their supplies having a similar impact would also be determined to be
non-BES.
Response: (1) and (2) - The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to
introduce the concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were
received questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white
paper that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to insure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
(3) The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus,
the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 3 Comment
the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order
773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks
will not be included in the bulk electric system, unless determined otherwise in the exception process.”
Colorado Springs Utilities
No
1.Can the standards drafting team clarify the reliability issue that they are trying to
mitigate with this language? What are we trying to prevent?
2.Why was the 30 kV threshold chosen as opposed to any other voltage, what is the
technical justification?
a.Instead of a kV threshold can we use a capacity rating, for example - use the 75
MVA rating used for collection point asset inclusion? I know that there has been
some discussion on this already, but we are not convinced that 30kV is a sound
threshold.
3.If we do decide to stay with a kV rating, then we need to ensure that the “nominal
voltage” is used as opposed to an “operating voltage.” This is important to prevent
a one-time operating voltage from drawings something in.
4.The “notes” should be incorporated into the definition itself, not left as notes to
create confusion or additional need for clarification down the road.
Response: The SDT is addressing FERC directives in Orders 773 and 773A and industry comments concerning the BES Definition
Phase 1 postings.
The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the concept to
the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received questioning the
threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper that is posted as a
supporting document for the second posting of this project which provides a review of regional criteria and contingency load flow
analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the value in Note 2 to 50 kV.
This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55 kV) to insure that a clear
bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
Consideration of Comments: Project 2010-17 | August 2, 2013
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Organization
Yes or No
Question 3 Comment
considered as radial systems, does not affect this exclusion.
The threshold value chosen represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55 kV) to
insure that a clear bright-line is established.
The SDT has considered the comments concerning the text and format of Note 2 and has decided to leave the format of Note 2 as
shown in the posting.
DTE Electric
No
30kV is too low, 60kV would be more realistic. The lower the voltage chose the great
the burden on industry in excluding these elements with no corresponding benefit
to reliability.
Northeast Power Coordinating
Council
No
Exclusion E1 provides a floor (30 kV threshold) for which an entity does not have to
consider the loop in its determination of a radial system. Due to the international
nature of the ERO, consideration must be given to what the various Provinces
consider to be “distribution level”, and any proposed revision should recognize this
dissimilarity. In addition, in the United States various state representatives have
cited jurisdictional issues associated with lowering the threshold to 30 kV. This also
impacts the 100 kV bright line threshold definition. The 30kV threshold as currently
written is too restrictive. In a similar way as 100 kV is the delineator between the
medium and high system voltage classes in the American National Standards
Institute (ANSI) standard on voltage ratings (C84.1), the voltage threshold in note 2
of exclusion E1 should be based on well defined standard system voltage classes to
better correlate to operational and system design considerations and practices.
The Exception Procedure could be used to include lower (than 100 kV; bright line)
voltage systems in the BES envelope when interactions between these systems and
the BES are deemed critical to reliable operations in their local or regional area. The
demarcation point between transmission and distribution may be different in nonFERC jurisdictions, such as the Canadian Provinces. For example, in Ontario,
legislation establishes 50kV as the technical boundary line between transmission
and distribution. In establishing voltage thresholds, NERC needs to consider non-
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U.S. legislated demarcation points, and the standard development process must
make allowances for such regulatory and/or jurisdictional differences. The
establishment of the voltage floor for the E1 exclusion as currently written is
inconsistent with the language and structure of the legislative framework in Ontario.
The Exception Process is not appropriate to determine the jurisdictional issue of
whether facilities are part of the Bulk Electric System. Note 2 should be modified to
read as follows: Note 2 - The presence of a contiguous loop, operated at a voltage
level below the applicable cut-off between configurations being considered as radial
systems, does not affect this exclusion. The applicable cutoff is 30kV or less, unless
deemed otherwise by regulatory authority. A technical justification is not required
where a Provincial jurisdictional finding is applicable.
Hydro One Networks Inc.
No
Exclusion E1 provides a floor (30 kV threshold) which an entity does not have to
consider the loop in its determination of a radial system. Data provided to the
drafting team shows that there are no transmission elements below 50 kV in
Ontario (and Canada) and very few in the 30-59 kV range (1%) in the US. A sub-set
of this 1% can be included as BES through the exception process if deemed
necessary for the operation of interconnected BES.
The demarcation point
between transmission and distribution may be different in non FERC jurisdictions,
such as the Canadian provinces. Accordingly, we suggest that the 30 kV threshold be
adjusted to 50 kV for Ontario (and Canada), since legislation establishes 50 kV as the
technical boundary line between transmission and distribution. It would also
alleviate any “unintended consequences” in future standards development. For
example, in Ontario, legislation establishes 50 kV as the technical boundary line
between transmission and distribution. In establishing voltage thresholds, NERC
needs to consider non-US legislated demarcation points, and the standard
development process must make allowances for such regulatory and/or
jurisdictional differences. The establishment of the voltage floor for the E1
exclusion is inconsistent with the language and structure of the legislative
framework in Ontario. Furthermore, we believe that the exception process is not
appropriate to resolve the jurisdictional issue of whether facilities are part of the
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BES or not. As such, Note 2 should be modified to read as follows: “Note 2 - The
presence of a contiguous loop, operated at a voltage of 30 kV or less, between
configurations being considered as radial systems, does not affect this exclusion for
US registered entities. For a non-US Registered Entity, the voltage level should be
implemented in a manner that is consistent with the demarcation points within
their respective regulatory framework.
MidAmerican Energy
No
MidAmerican believes the 30kV threshold is too low. MidAmerican believes that
the SDT should consider an “opt in” strategy for sub-100kV or Sub-60kV facilities
rather than the current proposed change which assumes facilities down to 34.5 kV
are in NERC scope unless entities “opt out” through the exemption process. Rather
than include them in the BES definition and require standard modifications to
exclude them when it is not appropriate, it is more efficient to modify those
standards where their inclusion is determined to be appropriate. This has already
been done in some recently modified standards (e.g. the generator verification
standards now filed for regulatory approval, the modifications made to standards
for the generator interconnections).
MRO NERC Standards Review
Forum (NSRF)
No
The NSRF believes the 30kV threshold is too low and the SDT justification is
inadequate. The BES operates at various kV classes. As power density and distance
grow, lower voltage classes are rendered ineffective at transporting bulk electric
system power. Therefore, certain voltage classes below 100 kV are clearly limited
in their ability to transport bulk electric power and should be ruled as distribution
facilities under the 2005 FPA.MRO members have expertise in performing
interconnected system modeling & operational analysis which indicates that all
three attributes comprising the technical justification used by the SDT are always
satisfied with the 60kV threshold. The recommended 60kV threshold recognizes
that 69kV is the lowest voltage at which loops between radial systems have the
potential to support adequate amount of power transfer under certain worst case
scenarios and thus may impact the >100kV system performance/reliability. In other
words, system modeling & operational analysis experience indicates that 69kV is the
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lowest voltage at which loops between radial systems present any possibility that
any one of the three attributes in the SDT’s technical justification may not be
satisfied. Or another consideration would be the Transmission Distribution Factor
(TDF) or percent participation. For example, entities could consider 24 - 69 kV
facilities with a 0.2 to 0.3% TDF and 50% or greater normalized transfer factor or
50% or more participation.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to insure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the
Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the
bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A,
paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not
be included in the bulk electric system, unless determined otherwise in the exception process.”
American Public Power
Association
No
APPA appreciates the SDT efforts to set a non-zero threshold for exclusion E1 as
proposed in Note 2. However, the 30kV voltage threshold selected is too low and
should be revised to exclude the 34.5 kV voltage class. APPA believes including
34.5kV facilities will create a significant compliance burden on registered entities,
especially small entities. To set a threshold this low will cast the compliance net
onto radial facilities that perform distribution functions that are not currently
subject to NERC reliability standards because these facilities are excluded as radials
serving load. APPA believes that selecting the 30 kV threshold will place an
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obligation on small entities to prove that power flows will not transfer through their
distribution systems for worst case scenarios. Without this change, APPA remains
concerned that addressing the 34.5 kV voltage class may overload the Rules of
Procedure (ROP) Exception Process. APPA recommends a higher threshold be
studied and proposes 40 kV as an alternative. In nearly all circumstances, the
distribution factors on 34.5 kV circuits that operate in normally closed
configurations parallel to 115 kV and higher BES paths differ by 20-to 1 or more, due
to the combined impact of relative line voltage impedances, transformer
impedances, and longer line lengths on the lower voltage path(s) that loop through
our load centers and then connect back to the BES. Further, 34.5 kV circuits rarely
affect SOLs or rated paths. These circuits rarely form part of the interface between
balancing areas. Exceptions to the general rule that could have a significant impact
on the BES should be addressed through the Exception Process. APPA's comments
to the Commission on BES Phase I Definition NOPR September 4, 2012: Should the
Commission in its final rule direct "other registered entities" to conduct a study of
all of their sub-100 kV facilities and state their potential impact to the Regional
Entity for evaluation for inclusion in the BES, then this directive would be excessively
burdensome to the industry, especially small registered entities. The Commission's
proposal would in effect require small registered entities (primarily Generator
Owners and Distribution Providers) to hire consultants to perform studies to assess
the potential impact of large numbers of non-BES facilities on the BES transmission
network. APPA requests that in the final rule the Commission give NERC and the
Regional Entities the flexibility to develop, with industry input, a reasonable
approach for the evaluation of sub-100 kV facilities that does not create an
excessive burden on the industry, especially small entities. Adoption of the 40 kV
threshold would largely alleviate this potential burden.
American Transmission Company
No
ATC believes the 30kV threshold is too low and should be increased to at least 50kV.
CenterPoint Energy
No
CenterPoint Energy recommends the voltage level of “30 kV or less” in Note 2 be
changed to “35 kV or less”. Based on this change, Note 2 would be: “The presence
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of a contiguous loop, operated at a voltage level of 35 kV or less, between
configurations being considered as radial systems, does not affect this exclusion.”
We suggest the voltage level should be established based on whether the
contiguous loop is operated at common distribution voltages (e.g., 12.47 and 34.5
kV). The vast majority of distribution feeders are, of course, operated radially.
Distribution feeders that are operated as a contiguous loop, or “networked”, are
equipped with “network protectors” that initiate tripping of interrupting devices. A
network protector automatically disconnects its associated power transformer from
the secondary network when the power starts flowing in the reverse direction; that
is, the interrupting device opens if the secondary grid back-feeds through the
transformer to supply power to the primary grid. Therefore, there cannot be any
loop flows between radial systems, as network protectors prevent such flows.
Hydro-Quebec TransEnergie
No
HQT do not agree that sub-100 kV looping should refrain radial exclusion, since it
doesn't carry impact on reliability of the BES, but only on non-BES. Though high
voltage below 100 kV should not constitute a looping, it is much more necessary
that medium voltage should not constitute a looping. According to ANSI and IEEE,
medium voltage is 35 kV.
National Grid
No
In a similar way as 100 kV is the delineator between the medium and high system
voltage classes in the American National Standards Institute (ANSI) standard on
voltage ratings (C84.1), the voltage threshold in note 2 of exclusion E1 should be
based on a well defined standard system voltage classes to better correlate to
operational and system design considerations and practices. This could e.g., be
done by aligning the voltage threshold with the insulator classes as defined in ANSI
standard on insulators (C29.13) or the maximum rated voltage in Institute of
Electrical and Electronics Engineers (IEEE) standards for medium voltage switchgear
(C37.20.2 and C37.20.4). Based on ANSI C29.13, the threshold in note 2 of exclusion
E1 could be set to 46 kV. The Exception Procedure could be used to include lower
(than 100 kV; bright line) voltage systems in the BES envelope when interactions
between these systems and the BES are deemed critical to reliable operations in
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their local or regional area.
Occidental Energy Ventures Corp.
No
OEVC agrees in general with the approach taken by the SDT to derive the 30 kV
limit. At some point, a practical limitation of the ability to evaluate the performance
of the low-voltage system dictates that a threshold be set. Taken to the absurd
logical extreme, without Note 2, the radial exclusion could be applied only after
every 115 volt household connection was evaluated. However, without a view into
the study results, we have no way to assess whether the 30 kV limit makes the most
sense. We fully respect the project team’s judgment, but it seems like this limit
could easily be set at 70 kV without any noticeable reliability impact.
National Rural Electric
Cooperative Association
No
On page 2, last paragraph, of the Unofficial Comment Form the language regarding
sub-100 kV loop analysis seems to indicate that the 30 kV level has already been
determined and selected through technical analysis. It is NRECA's understanding
that such technical analysis was not conducted prior to posting the phase 2 BES
definition, and that such analysis is being conducted now by a sub-group of the
drafting team. NRECA requests that the drafting team not focus on trying to
specifically justify the 30kV bright-line, but instead, it should develop a
methodology/test to determine the highest reasonable voltage level that we should
be using for application of Exclusion E1. Such methodology/test should take into
consideration the issues FERC identified in Order Nos. 773 and 773-A regarding their
concerns with sub-100 kV looping facilities under Exclusion E1 and other comments
from stakeholders that provide technical support or justification for certain voltage
levels for use in Exclusion E1.
ISO New England Inc.
No
The 30 kV limit in Note 2 for which an entity does not have to consider a loop
between two otherwise radial systems should be raised to 50 kV. There are
numerous 34.5 kV and 46 kV circuits used in distribution that would require review
with the 30 kV limit. The review required for those 34.5 or 46 kV circuits is not
warranted.
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New York Power Authority
No
The 30kV threshold is too restrictive and the sub-100kV loop threshold should be
determined by the method the SDT utilized by regional transmission system
makeup. This exclusion and restrictive loop threshold could lead to additional
exception requests.
Self
No
The 30 kV limit may be too low. 50kV or high limits may be technically justified. An
analysis to support the choice of any limit is needed.
IRC Standards Review Committee
No
The SDT describes the steps taken that led to proposing the 30 KV limit in Note 2 for
which an entity does not have to consider a loop between two otherwise radial
systems. However, the steps presented are not in our view technical justification for
the proposed threshold. Before we can support this proposal, we would appreciate
the SDT provide technical justification as to why 30kV is the appropriate level but
not any other voltage levels, e.g. why not 50kV or 69kV?
Tennessee Valley Authority
No
We agree with the approach, but not the voltage level chosen. Including loops
greater than 30 kV will be unreasonably burdensome. We believe the threshold
should be 70 kV. Any loops greater than 70 kV, that could affect the BES, should be
added through the exception process.
Texas Reliability Entity
No
We cannot support this proposal without an adequate technical justification
provided prior to the ballot. The posted materials indicate that the 30 kV threshold
was “based on initial discussions by sub-team; more discussion and analysis
needed.” Those materials only provide a rough outline of the analysis that could be
done; they do not indicate that any such analysis was actually done, and they do not
provide a technical justification. Also, there is no explanation of how the current
proposal is “equally effective and efficient” as applied to the Commission’s stated
concerns.
Orange and Rockland Utilities Inc.
No
We generally agree with the Drafting Team to introduce a threshold to Exclusion E1
but believe the Step 1 in the Low Voltage Level Criteria is arbitrary. ORU (RECO) is
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Question 3 Comment
the owner of the lowest threshold facility at 34kV facilities. The ORU (RECO) facilities
at 34kV and 69kV facilities do not have an impact on the BES. Our opinion is that
the 30 kV threshold is too low, therefore, we are requesting that the Drafting Team
consider a higher voltage level as a new threshold. If a monitored element/facility at
a lower voltage (sub-100 kV) level (including monitored Flowgates) does not pose
any impact to BES system, such element/facility should not be considered as a
criteria in E1 or E3.
New York State Department of
Public Service
No
While the goal of having some cut off level below which the facilities can clearly be
eliminated from consideration is theoretically reasonable, history has demonstrated
the designation can be abused and used for alternative purposes. There is no
technical basis for the 30 kV cut off. NERC has an obligation to provide technical
advice to FERC, so that any number provided to FERC is interpreted as technical
advice. NERC should not include any numbers in any definition or standard for
which it cannot provide a technical basis. Surveys do not provide a technical basis.
Discussions have indicated that because facilities less than 100 kV triggered a major
event in the southwest, a lower level voltage needs to be identified. Note that if
either the current NERC BES definition or a functional analysis had been applied to
the system at issue, either definition approach should have identified the involved
facilities as bulk elements. A lower threshold would therefore be superfluous, and
would be over-inclusive to an even greater degree than the current definition.
ACES Standards Collaborators
No
While we agree with the approach and thank the drafting team for their creativity in
coming up with the approach, we think it needs more refinement. There is a high
level description in the supporting documents of how this approach was arrived at.
However, there is a dearth of details. We think more details are necessary to agree
to the appropriate voltage level cutoff. For instance, 34.5 kV is a common
distribution voltage that can be networked. It is hard to fathom any networked 34.5
kV system could have a material impact on the BES because of its relative high
impedance. Thus, at a minimum, we suggest raising the cutoff to 35 kV to address
these situations. We also suggest supplying the detail data/reports that were used
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to arrive at the 30 kV cutoff.
Wisconsin Public Service / Upper
Peninsula Power
No
WPS believes the 30kV threshold is too low especially when 34.5kV is widely used
for distribution. Additionally, there are numerous instances where 46 kV is
appropriately classified as distribution through application of FERC’s 7-factor test
and we suggest a 50 kV threshold is more appropriate than a 30 kV threshold. The
BES operates at various kV classes. As power density and distance grow, lower
voltage classes are rendered ineffective at transporting bulk electric system power.
Therefore, certain voltage classes below 100 kV are clearly limited in their ability to
transport bulk electric power and should be ruled as distribution facilities under the
2005 FPA.
Xcel Energy
No
Xcel Energy asserts that the 30kV threshold proposed in Note 2 for Exclusion E1 is
too low, and instead proposes a 60kV threshold. Our extensive experience and
expertise in performing interconnected system modeling & operational analysis in
three diverse Regions (MRO, SPP, WECC) indicates that all three attributes
comprising the technical justification used by the SDT are always satisfied with the
60kV threshold. The recommended 60kV threshold recognizes that 69kV is the
lowest voltage at which loops between radial systems have the potential to support
adequate amount of power transfer under certain worst case scenarios and thus
may impact the >100kV system performance/reliability. In other words, Xcel
Energy’s system modeling & operational analysis experience indicates that 69kV is
the lowest voltage at which loops between radial systems present any possibility
that any one of the three attributes in the SDT’s technical justification may not be
satisfied.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
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Question 3 Comment
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to einsure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
Dominion
No
Dominion believes that there should be some way to insure that the requirement
does not require exclusion be validated solely by use of powerflow. We therefore
suggest the following revision to E1 (a) Only serves Load. A normally open switching
device between radial systems may operate in a ‘make before break’ fashion to
allow for reliable system reconfiguration to maintain continuity of service and not
require a powerflow model. We endorse the MRO comment - "The NSRF believes
the 30kV threshold is too low and the SDT justification is inadequate. The BES
operates at various kV classes. As power density and distance grow, lower voltage
classes are rendered ineffective at transporting bulk electric system power.
Therefore, certain voltage classes below 100 kV are clearly limited in their ability to
transport bulk electric power and should be ruled as distribution facilities under the
2005 FPA." We endorse the MRO Comment - "MRO members have expertise in
performing interconnected system modeling & operational analysis which indicates
that all three attributes comprising the technical justification used by the SDT are
always satisfied with the 60kV threshold. The recommended 60kV threshold
recognizes that 69kV is the lowest voltage at which loops between radial systems
have the potential to support adequate amount of power transfer under certain
worst case scenarios and thus may impact the >100kV system
performance/reliability. In other words, system modeling & operational analysis
experience indicates that 69kV is the lowest voltage at which loops between radial
systems present any possibility that any one of the three attributes in the SDT’s
technical justification may not be satisfied. "
SPP Standards Review Group
No
It is difficult to agree with the approach when the details of the evaluation and
analyses that were performed have not been made available for review by the
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industry. Once these details are known and have been reviewed by the industry, a
more informed decision on what voltage level should be incorporated into the
exclusion can be made. As it stands, we are very uncomfortable with the 30 kV limit
and feel it is too low. Is the contiguous loop referenced in Note 2 normally closed or
normally open? Whichever, it needs to be clarified in the note.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to einsure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
The operation of the normally open switches will not impact Exclusion E1.
Southern California Edison
No
The alternative identified as “Note 2” in the proposed Phase 2 BES Definition gives
preferential treatment to contiguous looped facilities, which should be defined as
LNs. The rationale used to justify this particular exclusion should be modified and
included in the BES Guidance Document so that it can be applied to both the E1 and
E3. With some minor revisions, the E1 loop exclusion rationale could similarly be
applied to LNs which connect to multiple points, such as within substations with
double breaker and breaker-and-a-half configurations. Another alternative would
be to identify LNs interconnected to the BES with breaker-and-a-half configurations
as radial systems, and be eligible for the E1 exclusion.
In addition, the 30kV looped facilities threshold identified for exempting looped
radial facilities is too low. This threshold has the potential to include facilities
owned and operated by transmission dependent utilities/ “Distribution Providers”
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Question 3 Comment
into the scope of the BES definition.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to insure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
Note 2 indicates that no ties below 50kV need to be considered when evaluating radials. The Local Network, Exclusion E3, contains
different requirements that an entity has to meet to utilize this exclusion. The looping facilities that operate at voltages below 100 kV
are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s interpretation,
does not propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless determined otherwise in the
exception process.” This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the
sub-100 kV elements comprising radial systems and local networks will not be included in the bulk electric system, unless determined
otherwise in the exception process.”
Independent Electricity System
Operator
No
The IESO does not agree with this approach as we identify two major concerns
related to Note 2 in Exclusion E1.First, by adding a new voltage threshold of 30 kV, a
new category of “wires” operated at voltages between 30 kV and 100 kV which may
become part of BES is effectively created. On the one hand, this would be
inconsistent with the BES definition introductory paragraph (Bulk Electric System
(BES): Unless modified by the lists shown below, all Transmission Elements operated
at 100 kV or higher and Real Power and Reactive Power resources connected at 100
kV or higher. This does not include facilities used in the local distribution of electric
energy). On the other hand, this could result in a huge effort/cost in part of all
facility owners as it appears that the intent is to include this new category of “wires”
in the BES elements and potentially rely on the BES Exception process to exclude
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Question 3 Comment
them one by one.
Second, the demarcation point between transmission and distribution may be
different in non FERC jurisdictions, such as Canadian provinces. For example, in
Ontario, legislation establishes 50kV as the technical boundary line between
transmission and distribution. In establishing voltage thresholds, NERC needs to
consider non-US legislated demarcation points, and the standard development
process must make allowances for such regulatory and/or jurisdictional differences.
The establishment of the voltage floor for the E1 exclusion is inconsistent with the
language and structure of the legislative framework in Ontario.
Furthermore, we believe that the exception process is not appropriate to determine
the jurisdictional issue of whether facilities are part of the bulk power system.
Therefore, the IESO proposal is to remove Note 2 altogether from Exclusion E1 and
rely on the BES Exception process to determine facilities operated below 100 kV that
must be included in the BES. In the alternative that Note 2 in Exclusion E1 is
retained, we request that it be modified to read as follows: “Note 2 - The presence
of a contiguous loop, operated at a voltage of 30 kV or less, between configuration
being considered as radial systems, does not affect this exclusion for US registered
entities. For a non-US Registered Entity, the voltage level should be implemented in
a manner consistent with the demarcation points within their respective regulatory
framework.
Northeast Utilities
While it is recognized that electrical systems operated below 100KV can be configured such that
they should require BES treatment (i.e. the 92 KV networked system involved in the 2011
Southern California - Arizona outage), a 30KV threshold is too low to significantly impact the
reliable operation of the higher voltage transmission system. We propose increasing this
threshold to a voltage in the 40-50KV range.
The new Note 2 associated with Exclusion E1 and the changes to E3 have added ambiguity that
did not exist before. The base definition does not address sub-100kV contiguous loops. The
existing Inclusions do not include sub 100kV contiguous loops either. Note 2 clarifies that as long
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as the contiguous loop is below 30kV E1 still applies. E3 explains how any sub 30kV contiguous
loop could be excluded as a local area network, but there is nothing in the definition to clearly
state that contiguous loops operated below 100kV are considered part of the BES unless excluded
by E3. An additional Inclusion should be added that specifically includes “all contiguous loop
operated below 100kV that is not solely used for the distribute power to load unless excluded by
application of Exclusion E1 or E3.”The proposed change to the E1 exclusion definition to add Note
2 will require an examination of NU sub-transmission system connections (69KV in CT and 34KV in
NH) and their connections to the >100KV transmission systems. Elements >100KV originally
categorized as E1 or E3 may become BES inclusions if there is underlying sub-transmission path.
A cursory review determine no elements categorized as E1 in CT would be changed; however, 16
of the 30 E1 elements in NH could become BES due to 34KV paths.
Response: The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155
states: “Thus, the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV
elements in figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the
Commission in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems
and local networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the concept to
the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received questioning the
threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper that is posted as a
supporting document for the second posting of this project which provides a review of regional criteria and contingency load flow
analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the value in Note 2 to 50 kV.
This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55 kV) to einsure that a clear
bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
The threshold value chosen represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55 kV) to
insure that a clear bright-line is established.
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Organization
Yes or No
American Electric Power
No
Question 3 Comment
While AEP does not necessarily disagree with the 30KV threshold, we are however
confused by the concept of a contiguous loop being part of a radial feed, as we find
“radial” and “loop” as mutually exclusive terms. This phrase is ambiguous and needs
further clarification before a voltage threshold can be discussed.
Response: Note 2 indicates that no ties below 50 kV need to be considered when evaluating radials. It should be noted that
normally open switches at any voltage will not disqualify the use of Exclusion E1. The looping facilities that operate at voltages below
100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s
interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless determined
otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in
the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not be included in the bulk electric system,
unless determined otherwise in the exception process.”
Associated Electric Cooperative,
Inc. - JRO00088
Yes
AECI appreciates the SDT's establishing a kV floor and yet feels that a 70kV floor
could accommodate FERC's concerns, with minor additions to establish some
threshold for obvious sub-network transfer-limitations between sub-network
transformer terminals.
Central Lincoln
Yes
Central Lincoln supports the approach, but questions the threshold. Central Lincoln
protests that the SDT plans to make its white paper on the technical analysis to
justify the 30 kV threshold available after the comment/ballot period is over. While
a 5 kV shift would not affect Central Lincoln, we are aware of entities that would be
in favor of a 35 kV threshold instead. Please give us the information needed to
evaluate the SDT's choice of 30 kV.
City of Tacoma
Yes
Comments: Many utilities utilize 35 kV distribution radial networks from a 2 or 3
transformer bank source. TPWR supports raising the 30 kV threshold to 35 kV.
Idaho Power Company
Yes
Idaho Power System Protection group: Yes, we agree with the approach in general,
but are concerned with a 30kV cutoff. In our system, connections are made in our
distribution load service at 35kV. If we are interpreting the language correctly, an
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Organization
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Question 3 Comment
evaluation would be required for all of our 35kV load service for any connections in
that subsystem, which represents a significant additional burden. Idaho Power
System Planning group: We are in favor of adding note 2 to Exclusion E1 of the BES
definition. However, we would suggest rewording note 2 as follows, while matching
the simplicity of note 1 of Exclusion E1: "A tie operated at a voltage of 30 kV or less
between radial systems does not affect this exclusion." We believe it is not the
intent to place the threshold of 30 kV or less on the contiguous loop that is created
by adding the tie between the two radial systems, but rather the intent is to place
the threshold of 30 kV or less on the tie itself between the two radial systems.
SERC EC Planning Standards
Subcommittee
Yes
If technical justification can be developed, a threshold of 70kV is recommended.
Sacramento Municipal Utility
District
Yes
SMUD supports the SDT’s approach but believes it to be prudent for the DT to
increase the voltage threshold to avoid unnecessary inclusions of rural electrical
systems.
Transmission Access Policy Study
Group
Yes
TAPS supports the SDT’s general approach and language in Note 2 to Exclusion E1.
In light of FERC’s interpretation of “radial,” it is vital that a minimum threshold be
added to Exclusion E1; without such a threshold, many TAPS members would have
to perform a more burdensome E3 analysis, and likely go through the much more
resource-intensive exceptions process, for Elements that are clearly not necessary
for the reliable operation of the grid. We therefore strongly support the SDT’s
proposal of a minimum threshold. TAPS does, however, suggest that the threshold
be 40 kV rather than 30 kV, because we believe that >100 kV radials connected by a
loop between 30 kV and 40 kV are highly unlikely to be necessary for the reliable
operation of the interconnected grid, and so 40 kV would be a more efficient
threshold than 30 kV; the rare case that should be part of the BES should be
included through the Exceptions process. We understand that the SDT has been
assembling technical support for a 30 kV proposal, and accordingly provide the
following evidence in support of using 40 kV instead. We propose 40 kV as being
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Organization
Yes or No
Question 3 Comment
between the commonly-used voltages of 34.5 kV and 46 kV. Neither threshold (30
kV or 40 kV) will capture “all and only” those Elements that should be part of the
BES, because neither threshold is (or can be) sufficiently granular; instead, the goal
should be for E1 (and the rest of the core definition) to get as close as possible to
the appropriate end-state, in order to minimize the need for case-by-case
Exceptions of either the inclusion or exclusion variety.
We understand that a primary reason behind the SDT’s use of 30 kV is the belief
that in some portions of the continent, voltages as low as 34.5 kV are monitored by
entities that have the responsibility to monitor to ensure the reliable operation of
the interconnected transmission system. We do not know which entities the SDT is
referring to (presumably it does not include all entities, since DPs monitor all
voltages), but we note that RFC and MISO, whose overlapping footprints are a very
significant area, monitor down to 40 kV. This suggests that the people with
responsibility and on-the-ground experience in those regions believe that 40 kV is
the threshold below which impacts can safely be assumed to be minimal.
Second, while the SDT has stated that it reads Order 773 as finding that impedance
alone is insufficient to demonstrate that looped or networked connections
operating below 100 kV should not be considered in the evaluation of Exclusion E1,
it is surely an important factor. The consideration of impedance supports a 40 kV
threshold. The impedance of a circuit is inversely proportional to the square of the
voltage. The amount of parallel flow is inversely proportional to the impedance of a
circuit. Thus, other things being equal, a 69 kV line carries 25% of the flow of a 138
kV line, and a 34.5 kV line carries 6.25% of the flow of a 138 kV line. Taking into
consideration other factors such as transformer impedances (which are usually
much greater than the impedances of the lines themselves) and the size and spacing
of conductors, TAPS members believe that the large majority of 30-40 kV loops
connecting >100 kV radials will carry less than 5% of the flow of a 138 kV line. For
purposes of Transmission Loading Relief in NERC and NAESB standards (IRO-006 and
WEQ-008, respectively), FERC has accepted a 5% transfer distribution factor as being
insignificant. It is therefore reasonable to allow >100 kV radials connected by a 34.5
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Question 3 Comment
kV loop to qualify for Exclusion E1: any loop flow is more likely than not to be
insignificant, and it is a waste of resources to require all such systems to assess their
eligibility for Exclusion E3 or go through the exceptions process. Instead, if there are
isolated cases of such configurations that should be included in the BES, they can be
added through the inclusion Exceptions process. Most TAPS members’ experience is
that 34.5 kV lines tend to be used for local distribution, while 69 kV (and sometimes
46 kV) is used for subtransmission. The goal, ultimately, is to have the all of the
necessary Elements, and no unnecessary Elements, in the BES. We believe that
using a 40 kV threshold will achieve that goal with fewer NERC, Regional Entity, and
registered entity resources than the 30 kV threshold proposed by the SDT.
Public Utility District No.1 of
Snohomish County
Yes
The Public Utility District No.1 of Snohomish County supports the SDT’s approach
and recommends increasing the voltage from “30 kV or less” to “35 kV or less”
noted in Question 1.
South Carolina Electric and Gas
Yes
We agree in general but if a technical justification can be developed, we
recommend a threshold of 70 kV.
NV Energy
Yes
While the details of the threshold voltage are still being ironed out, the concept of
this note acheives the objective of properly allowing for E1 exclusions in the
presence of distribution circuit loops or ties.
PacifiCorp
Yes
While the proposal is currently limited to a voltage level of 30 kV or less, PacifiCorp
suggests an expansion of the language to include minimum voltage levels based on
the characteristics of each interconnection (e.g., 30 kV for the Eastern
Interconnection and 40 kV for the Western Interconnection).
Pepco Holdings Inc & Affiliates
Yes
While we agree this approach addresses the Commissions sub-100 kV loop concerns
for radial systems, the choice of a 30 kV threshold seems somewhat arbitrary. The
intent is to allow small “distribution system” loops between connection points and
still satisfy the E1 exclusion for radial transmission systems. IEEE 100 “The
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Organization
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Question 3 Comment
Authoritative Dictionary of IEEE Standard Terms” defines a Distribution Line as
“Electric power lines which distribute power from a main source substation to
consumers, usually at a voltage of 34.5 kV or less.” Based on this industry
standard definition, we believe a 40kV threshold would be more appropriate, so as
to allow all looped distribution circuits, including those operating at 34.5kV, to
satisfy Exclusion E1 for radial systems.
Additionally, the rationale box included as part of Note 2 states: “.....As a first step,
regional voltage levels that are monitored on major interfaces, paths and monitored
elements to ensure the reliable operation of the interconnected system...” Just
because elements are monitored, does not necessarily mean that those elements
are specifically critical to the reliable operation of the system. In many cases it is
strictly a function of providing adequate data for the modeling of the system. It
would be unlikely that an underlying distribution loop would have any significant
impact on the transmission system. It may be possible that the underlying loop
system may itself have flow problems, but that is not the same as that loop creating
a problem on the transmission system.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to insure that a clear bright-line is established.
Note 2: The presence of a contiguous loop, operated at a voltage level of 3050 kV or less, between configurations being
considered as radial systems, does not affect this exclusion.
Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Yes
Southern generally agrees with the SDT’s approach in adding Note 2 to Exclusion E1
to address FERC’s concerns regarding sub-100kV loops for radial systems.
Respecting and appreciating that the SDT may have intended to mirror not only the
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Organization
Yes or No
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
Question 3 Comment
concept, but also the language and format of Note 1 immediately above, Southern
believes the language “does not affect the exclusion”, by itself, can be confusing to
entities trying to make applicability and compliance determinations. To more
directly and clearly articulate the concept of “not affecting the exclusion” as
meaning that the described configuration qualifies for the exclusion and thus is
excluded from the BES, Southern suggests the following revised Note 2 in quotes
below. To the extent similar language can also be added to Note 1, Southern
believes that it would also benefit from the added clarity. “Note 2 - The presence of
a contiguous loop, operated at a voltage level of 30 kV or less, between
configurations otherwise being considered as radial systems, does not affect this
exclusion from applying, and thus such configurations should be eligible for
Exclusion E1 and thus not included in the BES.”
Response: Note 2 indicates that no ties below 50kV need to be considered when evaluating radials. It should be noted that normally
open switches at any voltage will not disqualify the use of Exclusion E1. The looping facilities that operate at voltages below 100 kV
are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s interpretation,
does not propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless determined otherwise in the
exception process.” This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the
sub-100 kV elements comprising radial systems and local networks will not be included in the bulk electric system, unless
determined otherwise in the exception process.”
FirstEnergy
Yes
Cooper Compliance Corp
Yes
Iberdrola USA
Yes
PPL NERC Registered Affiliates
Yes
FirstEnergy supports the proposed 30kV threshold for Exclusion E1 based on the
explanation provided in the June 26, 2013 industry webinar and information
presented by the drafting team in the supplemental material/presentation titled
“BES Radial Exclusion Low Voltage Level Criteria”.
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Question 3 Comment
North American Generator Forum Yes
Standards Review Team
Arizona Public Service Company
Yes
Southwest Power Pool Regional
Entity
Yes
US Bureau of Reclamation
Yes
Public Service Enterprise Group
Yes
Manitoba Hydro
Yes
Georgia Transmission
Corporation
Yes
Duke Energy
Yes
Modesto Irrigation District
Yes
American Wind Energy
Association
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Response: Thank you for your support.
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4. The SDT has revised the generation resources and dispersed power resources inclusions (Inclusions I2 and I4) in response to
industry comments and Commission concerns. Do you agree with these changes? If you do not support these changes or you
agree in general but feel that alternative language would be more appropriate, please provide specific suggestions in your
comments.
Summary Consideration: The SDT has considered the comments of the industry and determined that the point of aggregation at which
dispersed generation could have a reliability impact on the BES is at 75 MVA and therefore the SDT has broken apart Inclusions I2 and I4
to provide the consistency, clarity, and granularity that these inclusions require. The SDT believes that these changes adequately
address the ambiguity caused by the use of the term “generator terminals” within the definition.
Many commenters feel that existing standards do not adequately address the different generator types, fuel sources, and intermittency.
It is recommended that standard applicability be addressed through a new SAR prepared by industry.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources aggregate to
greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
Organization
Yes or No
Texas Reliability Entity
No
Question 4 Comment
(1) We have no objection to combining conventional and dispersed generating
facilities into one BES inclusion, but we do object to the characterization (in the blue
box) of wind farms as “small-scale power generation technologies.” In the ERCOT
region there is now over 10,000 MW of installed wind capacity. Wind generation
sometimes has served up to 25% of the entire ERCOT load, and wind provided over
9% of energy produced in ERCOT in 2012. Large-scale wind resources (facilities over
75 MVA) must be included within the BES and subject to appropriate reliability
standards.
(2) We would like to see clarification that dispersed power producing resources are
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Question 4 Comment
generally viewed in the aggregate rather than as separate BES elements. The
performance of each individual wind turbine and element of the collector system is
not a large concern, but we are concerned about the reliability impact of 75+ MVA
of generation connected to the transmission system. We encourage the team to
consider viewing a BES wind farm as an aggregated generating facility, including the
turbines, the collector system, and the step-up transformer. Such an aggregated
generating resource should have an associated GO and GOP, and be subject to
appropriate reliability standards.
Response: The SDT respectively disagrees with your comment that wind farms are not small scale power generation technologies.
Individual turbines have been categorized as small scale due to their nameplate rating, not their aggregate capacity. In response to
your comment and many others regarding the need to view dispersed generation in aggregate, the SDT has broken apart Inclusions I2
and I4 to provide the clarity and granularity that these inclusions require.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a)
Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
ACES Standards Collaborators
No
(1) While we are not opposed to combining I2 and I4, we think I4 provides additional
clarity and granularity. I4 collectively with the Phase 1: BES Definition Reference
Document is very clear that the collector system is not included in the BES.
Exclusion of the collector system is not clear from I2 particularly without a modified
reference document. If the combination of I2 and I4 persists, we recommend that
the reference document should clearly state that the collector system is not
included similarly to the current version.
(2) We do not understand why the question states that the changes address
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Question 4 Comment
Commission concerns. The Commission was very clear in approving I4. Paragraph
58 of Order 773-A states the “Commission ... confirms its finding that including I4
provides useful granularity in the bulk electric system definition.” By combining I4
into I2, this granularity is removed.
American Electric Power
No
AEP does not believe that the generator terminals of individual dispersed power
producing resources should by default be included in the BES definition. We suggest
revising I2 to include dispersed power producing resources from the point of
connection where the resource’s aggregate nameplate rating is greater than 20 MVA
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above. As currently drafted, individual wind turbines would be included as part of
this definition. AEP offers the following additional reasons why individual wind
turbines specifically should not be in scope:*Given their small size and interment
availability of the prime mover, they do not individually constitute a risk to the
reliability of the BES.* The ability of the GO to perform maintenance and testing
activities required by PRC-005-2 is limited due to the physical design of the system
and may also be limited due to warranty agreements with the OEM.* A wind farm
may experience hundreds of breaker operations a day and have not automated
ability to determine whether the operation was caused by a Protection System
operation. Under this scenario, the resources needed to show compliance with the
proposed PRC-004-3 may be unduly burdensome to the GO.
Exelon and its Affiliates
No
Exelon does not support the changes made to items I2 and I4 in the proposed BES
Definition. By combining items I2 and I4, the BES DT has effectively pulled in
dispersed power producing resource collector system elements which are <100kV
and which do not normally carry >75MVA in aggregate flow. In doing so, the BES DT
has inappropriately strayed from the work plan for Phase 2 as defined in the Phase 2
original and supplemental SARs. In the original Phase 2 SAR, the BES DT was tasked
with providing technical justification for the following items; 1. Develop a technical
justification to set the appropriate threshold for Real and Reactive Resources
necessary for the reliable operation of the Bulk Electric System (BES) 2. The NERC
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Yes or No
Question 4 Comment
Board of Trustees approved BES Phase 1 definition does not encompass a
contiguous BES - Determine if there is a need to change this position 3. Determine if
there is a technical justification to revise the current 100 kV bright-line voltage level.
4. Determine if there is a technical justification to support allowing power flow out
of the local network under certain conditions and if so, what the maximum
allowable flow and duration should be. Additionally, the Phase 2 original SAR tasked
the BES DT with improving the clarity of the following items;1. The relationship
between the BES definition and the ERO Statement of Compliance Registry Criteria
established in FERC Order 693 2. The use of the term “non-retail generation” 3. The
language for Inclusion I4 on dispersed power resources 4. The appropriate ‘points of
demarcation’ between Transmission, Generation, and Distribution. Finally, the
supplemental Phase 2 SAR required the BES DT to:1. Address the directives in FERC
Order 773 issued December 20, 2012 The proposed changes to I2 and I4
inappropriately exceed the work plan as outlined in the SARs because they do not
improve clarity for I4 and they are not in response to a directive from FERC Order
773. In Phase 1, the BES DT intended to exclude the collector system elements for
dispersed power producing resources and stated so multiple times in responses to
stakeholder comments, webinars and in the original draft of the Guidance
document. By changing positions on whether collector systems should be included
in the BES, the BES DT has not improved clarity but has instead materially changed
the BES Definition itself. In addition, in Order No. 773, FERC specifically declined to
“direct NERC to categorically include collector systems pursuant to inclusion I4”.
(Order No. 773, P114). Therefore this change is not in response to a FERC directive.
Furthermore, under the current registration criteria for inclusion in the NERC
Registry, Generation Owners and Generation Operators for individual generation
resources >20MVA connected at 100KV or higher or aggregate resources > 75MVA
(Aggregate) connected at 100KV or higher are required to register and are thus
subject to the NERC Reliability Standards. Individual elements of dispersed power
producing resources do not reach these thresholds until the point of where all of the
elements are summed together. The individual dispersed power producing resource
elements before this “summed” point have little or no impact to the BES as they are
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Organization
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Question 4 Comment
generally isolated from the BES behind protection system elements such as relays
and circuit breakers. Exelon feels that only those elements in a collector system that
carry more than 75 MVA of aggregate flow should be included in the BES. Thus,
Exelon opposes the changes to I2 and I4 in the current Phase 2 draft BES definition
and has submitted a NEGATIVE vote on the proposed BES definition.
MidAmerican Energy
No
In plants with an aggregate rating greater than 75 MVA, the individual generators
should be treated in the same manner as they would be in a stand-alone facility. If
the individual generator is at or below 20 MVA in a stand-alone facility it would not
be included in the BES and the owner of such a facility would not even have to
register as a generator owner. That same size generator in an aggregated facility
should be treated the same and it should be excluded from the BES. The portion of
the facility at which the 75MVA or greater aggregation occurs should be where the
BES boundary occurs.
Inclusion I2 has been modified to incorporate I4 and I4 was eliminated. This is a
good step, but the wording needs to be revised to recognize the relative
insignificance of the small generators to the bulk electric system. There may be
cases in some requirements of some standards where it is appropriate to include
generators below 20 MVA in those requirements. Rather than include them in the
BES definition and require standard modifications to exclude them when it is not
appropriate, it is more efficient to modify those standards where their inclusion is
determined to be appropriate. This has already been done in some recently
modified standards (e.g. the generator verification standards now filed for
regulatory approval, the modifications made to standards for the generator
interconnections).Here is the proposed markup:”I2 - Generating resource(s) and
dispersed power producing resources with: a) Gross individual nameplate rating
greater than 20 MVA, including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above, OR, b) Gross
plant/facility aggregate nameplate rating greater than 75 MVA, beginning at a bus
where the aggregate generation is greater than 75MVA and continuing thru the
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Question 4 Comment
high-side of the step-up transformer(s) connected at a voltage of 100 kV or above”
NextEra Energy
No
Inclusion I2 has been modified to incorporate I4 and I4 was eliminated. This is a
good step, but the wording needs to be revised to recognize the insignificance of the
individual wind turbine generators to the bulk electric system. Here is the proposed
re-write:”I2 - Generating resource(s) and dispersed power producing resources with:
a) Gross individual nameplate rating greater than 20 MVA, including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage
of 100 kV or above; or, b) Gross plant/facility aggregate nameplate rating greater
than 75 MVA, beginning at a bus where the aggregate generation is greater than
75MVA and continuing thru the high-side of the step-up transformer(s) connected at
a voltage of 100 kV or above” 100kV bright line: The use of the 100kV bright line is
recommended to be continued in the base definition, the inclusions and exclusions.
Specific analysis should be performed to demonstrate the need for change on an
individual basis.
Response: The SDT agrees with your comments and has revisited Inclusions I2 and I4. The inclusions have been broken apart to
provide the clarity and granularity that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a)
Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
American Wind Energy
Association
No
AWEA is seriously concerned that taking the body of NERC reliability standards that
now apply to Bulk Electric System (BES) components and indiscriminately applying
them to dispersed power producing resources under the proposed Inclusions I2 and
I4 will impose a major burden and potentially result in significant confusion about
the applicability of standards, with little to no benefit for electric system reliability.
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Question 4 Comment
These inclusions as currently drafted could potentially even harm electric reliability
by misallocating attention and resources away from concerns that are far more likely
to negatively affect BES reliability. AWEA strongly urges that the BES definition be
revised to only apply to the Point-of-Interconnection with the bulk electric system,
as that is the only place within the wind project where more than 75 MVA of
generating is aggregated and thus could reasonable affect BES reliability.
In the alternative, we ask that NERC revise Inclusion I2 as follows:I2 - Generating
resource(s) [DELETE: and dispersed power producing resources,] including the
generator terminals through the high-side of the step-up transformer(s) connected
at a voltage of 100 kV or above with: a) Gross individual nameplate rating greater
than 20 MVA, OR, b) Gross plant/facility aggregate nameplate rating greater than 75
MVA. [ADD: The application of individual NERC BES-relevant standards to dispersed
generation resources is to be specified in the applicability section of individual
standards.]The intent of this revision is to ensure that before BES-relevant standards
are applied to dispersed generators, each standard is evaluated to determine
whether it is reasonable to apply that standard to dispersed generators and whether
applying that specific standard to dispersed generators will significantly improve
electric reliability. Many NERC standards that apply to the BES were crafted before
the significant growth of dispersed generation and without dispersed generators in
mind. Combined with the fact that many dispersed generators are variable
renewable resources that have limited capacity value and are asynchronously
connected to the power system, many NERC standards are likely to have limited
applicability or benefit if applied to dispersed generators. To our knowledge, a
compelling rationale has not been provided for why applying all NERC BES- relevant
standards to dispersed generators would significantly improve BES reliability. A
blanket application of NERC standards to dispersed generators by including them in
the definition of BES would be unduly burdensome, confusing, and provide little to
no reliability benefit. As of the end of 2012, per AWEA’s Annual Market Report,
there were approximately 45,100 utility-scale wind turbines operating in the U.S.,
many of which are aggregated in wind projects that exceed 75 MVA in aggregate
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and are connected at a common point of voltage of 100 kV or above. Including each
of these wind turbines and their collector systems in the BES definition would
impose a large and undue burden on wind project owners and operators by
potentially forcing them to comply with a number of NERC compliance processes
and reliability standards that were crafted with large central-station generators in
mind and cannot reasonably be applied to each of the dispersed generators within a
wind project. We do not believe that the body of NERC requirements are adequately
adapted to the technical differences of small, aggregated generation units. For
example, the administrative burden and cost of complying with the GO/GOP
standards at the individual generating unit level would be very substantial. For
standards such as PRC-005, R1, and R2, applying these standards to dispersed
generators would call for regular relay and protection system testing at numerous
places within the wind plant, potentially including the internal circuitry of each
individual wind turbine. One wind plant owner has indicated that, for one of its
plants, applying the BES definition to the individual dispersed generators would
increase the number of elements subject to the PRC-005 maintenance and testing
requirements by more than a factor of 100. As another example, TOP-002 R14 and
TOP-003 R1 require status reporting of unplanned and planned generator outages,
respectively. We do not believe that the Balancing Authority (BA) or Transmission
Operator (TO) would benefit from being notified about the operational status of any
single dispersed generator at the typical wind turbine size of 2 MW or less. For the
VAR series of standards, small size voltage control and waveform stabilization
circuitry could require operational status monitoring and outage notification to the
TO for this equipment. There are many other examples of potential confusion or
unnecessary work and cost that can arise from the inclusion of small, individual
dispersed generation assets, and their aggregation circuitry and equipment, in the
BES definition. Most importantly, no one has demonstrated that there would be any
material reliability benefit from applying all BES component standards to individual
dispersed generators. The nameplate capacity of an individual wind turbine
generator rarely exceeds 3 MW, and the average output of such a turbine is typically
under 1 MW. Moreover, the capacity value contribution that grid operators typically
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assume for wind projects for meeting peak electricity demand is typically less than
20% of the nameplate capacity of the wind project. In the typical electrical layout of
a wind plant, around a dozen wind turbines are aggregated onto an electrical string
of the collector array (which operates at voltages well below 100kV), so even losing
a single electrical string or even multiple electrical strings will typically only result in
the loss of a few dozen MW of generation at most. Such minimal impacts fall well
below the 75 MVA threshold that Inclusion 4 seeks to establish for determining what
should be included in the definition of the BES, as well as any reasonable threshold
for determining which electrical components are likely to cause a reliability problem
on the BES. In contrast, the electrical equipment at the Point-of-Interconnection
(POI) with the BES (and not the individual generators and their collector system), is a
far more appropriate point for delineating between the BES and non-BES electrical
components and implementing a blanket application of NERC standards for BES
components, as the POI for a wind project comprised of more than 75 MVA of
generation and operating at more than 100 kV is the only part of the wind project
that could reasonably affect BES reliability. One of the only credible arguments for
requiring that all BES reliability standards apply to individual wind turbines is if one
believed that wind turbines could be potentially susceptible to a common mode
failure that would cause a large number of the generators within a wind plant to trip
offline within a matter of seconds. Fortunately, all wind turbines installed in the U.S.
in recent years and going forward are already compliant with the demanding voltage
and frequency ride-through requirements of FERC Order 661A, which are far more
stringent than the ride-through requirements placed on other types of generation.
In the event of a system disturbance that causes a voltage or frequency deviation
that would affect all generators nearly simultaneously, a wind plant would be more
likely to remain online than almost all conventional generators, and the wind plant
would likely only trip offline if the power system had collapsed to the point that
nearly all other generation had already tripped offline. As a result, there is no
compelling reliability reason for including individual wind generators and their
electrical collector systems in the BES definition. Applying all BES-relevant standards
to individual dispersed generators not only fails to improve electric reliability, but it
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could even potentially harm electric reliability by misallocating attention and
resources away from concerns that are far more likely to negatively affect BES
reliability. Scarce resources exist for maintaining power system reliability, and
devoting resources and attention to an issue that is unlikely to affect BES reliability
can actually harm reliability by distracting attention from components that are more
likely to cause a reliability problem. Moreover, taking the whole body of standards
that were drafted with large central-station generators in mind and indiscriminately
applying them to dispersed generators with very different characteristics is likely to
cause significant confusion, further distracting from efforts that are important for
maintaining and improving bulk power system reliability. As a result, the BES
definition should be revised as indicated above, to ensure that before BES-relevant
standards are applied to dispersed generators, each standard is evaluated to
determine whether it is reasonable to apply that standard to dispersed generators
and whether applying that specific standard to dispersed generators will significantly
improve electric reliability.
Response: The SDT has revisited Inclusions I2 and I4. The inclusions have been broken apart to provide the clarity and granularity
that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources aggregate
to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
With regard to the applicability of NERC standards to dispersed generating resources, or wind turbines specifically, it is
recommended that a SAR be generated by the industry to address the applicability of standards to specific types of generation.
Northeast Power Coordinating
No
It should be considered that dispersed generators that are represented to the
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Question 4 Comment
marketplace or modeled in study cases as 20MVA or higher should be included in
the definition just as a single traditional generating unit of 20 MVA is included. By
removing I4, the aggregating portion of the inclusion has been muddied. Suggest
adding I2-c to include dispersed resources that are aggregated and modeled at
20MVA or higher. This would add clarity and consistency to the definition.
The impact of the proposed response to Commission directives (and the directives
themselves) in effect bring wind generation collector systems and any other
aggregation system for other resource technologies into the definition of Bulk
Electric System. Recommend that there be an exclusion for wind generation
collector systems which are radial in nature and do not serve any retail load
provided adequate protection for the BES via protective systems installed at the
point of interconnection. Bringing many thousands of 1-2 MW generators directly
into the reliability regime of the ERO is not necessary, or justified. In plants with an
aggregate rating greater than 75 MVA, the individual generators should be treated
in the same manner as if they were each a stand-alone facility. If the individual
generator is at or below 20 MVA in a stand-alone facility it would not be included in
the BES and the owner of such a facility would not even have to register as a
generator owner. That same size generator in an aggregated facility should be
treated the same and it should be excluded from the BES. The portion of the facility
at which the 75MVA or greater aggregation occurs should be where the BES
boundary should be occurring. To demonstrate the concept, an illustration marked
as Figure 1 has been submitted to Monica Benson (NERC). From FERC Order 733A
beginning at paragraph 50, “we direct NERC to modify the exclusions pursuant to
FPA section 215(d)(5) to ensure that generator interconnection facilities at or above
100 kV connected to bulk electric system generators identified in inclusion I2 are not
excluded from the bulk electric system”. To that end, I2 should be revised to read:
I2 - Generating resource(s) and dispersed power producing resources, including their
power delivering assets operated at a voltage of 100 kV or above with:
New York Power Authority
No
It should be considered that dispersed generators that are represented to the
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marketplace or modeled in study cases as 20MVA or higher should be included in
the definition just as a single traditional generating unit of 20 MVA is included. By
removing I4, the aggregating portion of the inclusion seems to be less clear. One
suggestion would be to add I2-c to include dispersed resources that are aggregated
and modeled at 20MVA or higher are included. This would add clarity and
consistency to the definition.
PacifiCorp
No
PacifiCorp does not agree with the proposed changes to Inclusions I2 and I4 because
such changes would include generating resources within the BES regardless of a
resource’s individual MVA rating and all of the equipment from each generator
terminal to the > 100 kV transmission interconnection if the facility aggregate rating
exceeds 75 MVA. A similar outcome was included in the Phase I definition in the
previous version of Inclusion I4 that addressed dispersed power producing resources
specifically and, as a result, one of the SDT’s tasks in the Phase 2 SAR was to address
the treatment of dispersed power producing resources. A dispersed power
generating facility necessarily consists of individual units of a limited size to take
advantage of the distributed nature of the resource (e.g., wind or solar) upon which
the facility relies for its fuel source. One benefit of such facilities’ unit size and
geographical distribution is that they are not as susceptible to a substantial loss of
generating capability as a single unit of 20 MVA or greater (the registration
threshold for a single generating unit). If the arrayed generators were each 2 MVA
then the probability of losing 20 MVA at the generator level would be .00000001%.
If the units were 5 MVA each the probability of losing all four units at the generator
level would be .01%. The probability of losing a single 20 MVA unit would be 10%.
These variations illustrate that there will be different values depending upon the
arrayed generator’s size. Given the reliability advantage this diversity affords it does
not seem reasonable to treat this type of facility in the same way as a single unit
facility of 20 MVA or greater. As recognized by the SDT and FERC in Order No. 773, a
dispersed generating facility of 75 MVA or greater (NERC Registry Criterion Section
III.c.2) can have an impact on the BES. To recognize this impact and to also account
for the dispersed nature and reliability advantage as described above, PacifiCorp
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requests that the SDT strongly consider the following two potential alternative
revisions to the proposed Inclusion I2:PacifiCorp’s preferred option would be:”I2 Generating resource(s) and dispersed power producing resources, with: a) Gross
individual nameplate rating greater than 20 MVA, including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above, OR, b) Gross plant/facility aggregate nameplate rating greater than 75
MVA, beginning at a bus where the aggregate generation is greater than 75 MVA
and continuing through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.”The following diagram demonstrates the 75 MVA
aggregation impacted by PacifiCorp’s preferred option: (diagram provided to Wendy
Muller at NERC).This preferred option would also include traditional sources of
generation comprised of several small generators. NERC’s registration criteria would
still include this type of a facility as a registered GO or GOP.
PacifiCorp’s second option is:”I2 - Generating resource(s) and dispersed power
producing resources, including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above with: a) Gross
individual nameplate rating greater than 20 MVA, OR, b) Gross plant/facility
aggregate nameplate rating greater than 75 MVA. For facilities with an aggregate
rating of 75MVA or more that consist of individual units rated at 4 MVA or less, the
portion of the facility that is included in the BES as generation shall start at the point
at which the 75MVA or greater aggregation occurs and continue out to the
interconnection with the transmission system rated at 100 kV or more.”Under this
proposed change, a dispersed generating facility of 75 MVA or more consisting of
individual generators of 4 MVA or less would be included in the BES definition as
generation resources in a similar manner as other types of generation resources, but
the unique nature of the small, distributed generating units that comprise them and
their inherent reliability advantages would also be appropriately recognized in the
definition. NERC’s registration criteria would still include this type of a facility as a
registered GO or GOP. **Please see diagram at the end of the report (P. 126)**
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Self
No
Proposal for I2 as follows:I2 - Generating resource(s) and dispersed power producing
resources, including their power delivering assets operated at a voltage of 100 kV or
above with:
Hydro One Networks Inc.
No
The combination of I2 with I4 is not as a result of FERC’s directive and/or clearly
stated in the scope of the Phase 2 SAR. In Order 773, Commission states: a) “Other
than the directive to modify exclusion E3 as discussed below, the Commission
declines to direct NERC to further modify the definition or the specified inclusions
and exclusions” (Paragraph 52)b) the Commission will not direct NERC to
categorically include collector systems pursuant to inclusion I4. (Paragraph 114)We
believe that I2 and I4 wordings as approved by the stakeholders, NERC BoT, FERC
and applicable governmental authorities in Canada should be retained. As such, we
do not support this change to the definition because NERC should also consider
unintended consequences that could result out of this change. In our opinion, I4 is
meant for renewable energy resources (in particular Wind). These resources are
inherently different from both the planning and the real time operations
perspectives. This change will essentially designate every element of a wind farm
above 75 MVA to its interconnection as a BES facility including the collector systems
which may not be necessary. For example, this will essentially mean that collector
systems shall be required to comply with TPL standards performance assessment
and design.
North American Generator
Forum Standards Review Team
No
The equipment being included in compliance with NERC Standards should only be
that equipment carrying >75 MVA - the collector systems, GSU and Gen Tie, not the
individual turbines. Implementing standards at the individual wind turbine level (<
2MW in many cases) does not improve reliability and only created additional
workload for both the registered entities and the regions. A 2 MW wind generator
will neither have an impact due to the loss of the generation nor start cascading
outages due to a failure to trip a 600 volt machine. As a point of reference, many
large generating stations have station service loads of that magnitude.
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Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
No
The equipment being included in compliance with NERC Standards should only be
that equipment carrying >75 MVA - the collector systems, GSU and Gen Tie, not the
individual turbines. Implementing standards at the individual wind turbine level (<
2MW in many cases) does not improve reliability and only created additional
workload for both the registered entities and the regions.
Public Utility District No.1 of
Snohomish County
No
The Public Utility District No.1 of Snohomish County supports the omitted I4 and
does not support the revisions to the generation resources and dispersed power
resources inclusions. The change will classify systems as BES that interconnects a
generation unit with a peak generation capability of less than 2 MVA and typical
capacity factor of 25-30 percent. It is difficult to understand how these types of
systems could be considered bulk. A greater than 75 MVA plant would typically
have many miles of a 34.5 kV collector system connecting 480/690 volt to 34.5 kV
generator step up transformers. Failure or mis-operations of these collector system
components would equate to the loss of a MW or two, 30 percent of the time. The
Public Utility District No.1 of Snohomish County does not believe enforcing NERC
Reliability Standards on these, or similar systems supports reliability. In fact it could
stifle green distributed generation developments.
City of Tacoma
No
TPWR supports the omitted I4 and does not support the revisions to the generation
resources and dispersed power resources inclusions. The change will classify
systems as BES that interconnects a generation unit with a peak generation
capability of less than 2 MVA and typical capacity factor of 25-35 percent. It is
difficult to understand how these small generation systems could be considered BES.
Pattern Gulf Wind LLC
No
While generators should not be seperated into different categories, and I agree with
the general concept to combine power/generation resources into one inclusion, I
disagree with the lanugage that for dispersed power resources the entire generation
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facility up to the generator terminal becomes part part of the BES. The critical load
for dispersed power resources (considering the actual Net Capacity Factors) is
apparently reached at an output of 75 MVA. Including equipment such as collector
circuits and individual generators that carry well below the critical load of 20 MVA as
applicable to conventional generators does seem unreasonable and undue and will
have very little to do with protecting reliability and the BPS, but will increase
maintenance and operating cost to unjustifieable levels. Only at the point where the
such generation is aggregated and a critical load can be reached would dispersed
power generators meet any criticality to the BPS, but the loss of individual small
generators or collection circuits would not have significant impact on the BPS
including causing any cascading outages. Equipment included in compliance with
NERC standards(as handeled in practise for the past 5+ years) should be limited to
the point where generation is aggregated including the GSU and (if owned/operated
by GO/GOP) generator tie-lines.
Wisconsin Electric
No
Wisconsin Electric supports the comments filed by the NAGF in response to this
question with the following edits: “The equipment being included in the BES
definition should only be that equipment that actually carries greater than 75 MVA the collector systems, main transformers, and high-voltage interconnections, not the
individual wind turbines. Implementing standards at the individual wind turbine
level (<2 MW in many cases) does not improve reliability and only creates additional
workload for both the registered entities and the Regions. A 2 MW wind generator
will neither have an impact due to the loss of generation nor cause cascading
outages due to a failure to trip a 600 volt machine.
Wisconsin Public Service / Upper
Peninsula Power
No
WPS recommends that both I2 and I4 be retained, yet reworded such as this:”I2 Generating resource(s) and dispersed power producing resource(s), with gross
individual nameplate rating greater than 20 MVA, including the generator terminals
through the high-side of the generator step-up transformer(s) connected at a
voltage of 100 kV or above.””I4 - For generating and dispersed power producing
facilities with gross plant/facility aggregate nameplate rating greater than 75 MVA,
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the bus where the aggregate generation is greater than 75 MVA and continuing thru
the high-side of the step-up transformer(s) connected at a voltage of 100 kV or
above. (Note: this does not include the individual generating resources themselves,
or the collector feeder system(s).)”The intent is to focus compliance activity at the
point where power is aggregated to the point (usually a bus) where it becomes
significant to the BES not at small (1 to 2 Mw) generators or distribution level Mw
collector systems. The reliability issue for small generating units whether they are
diesels, wind turbines, solar units, or nuclear modules is not the risk of loss of small
independent individual units. The common mode risk of loss of significant amounts
of generation is at the point of aggregation.
Transmission Access Policy Study
Group
An unintended consequence of the merging of I2 and I4 could be that dispersed
behind-the-meter retail customer generation, which itself is not BES under Exclusion
E2, results in the distribution system on which it is located being a BES collector
system under I2. TAPS offers three options to resolve this unintended consequence.
The first option is to bring more of the former I4 language into I2, e.g., “utilizing a
system designed primarily for aggregating capacity” to the inclusion, so that I2
would read: Generating resource(s), and dispersed power producing resources
utilizing a system designed primarily for aggregating capacity, including the
generator terminals through the high-side of the step-up transformer(s) connected
at a voltage of 100 kV or above with:a) Gross individual nameplate rating greater
than 20 MVA, OR, b) Gross plant/facility aggregate nameplate rating greater than 75
MVA.
The second option is to include the term “non-retail” after dispersed and before
power producing.
And the third option is to clarify the use of the term “plant/facility” in b) such that it
is clear that it does not refer to all the retail back-up generators or net-metering
power producing resources connected to one distribution system connected to one
connection to > 100 kV.
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TAPS also notes that many reliability standards are not a good fit for small individual
generating units at dispersed, intermittent power resources such as wind farms; for
example, given the frequency with which wind turbines trip on and offline (as they
are designed to do), tracking each operation at each turbine to determine whether
any misoperations have occurred would extremely onerous and yield minimal
reliability benefit. We acknowledge that this concern is outside the scope of this
project, but believe that the SDT should be aware of the issue as it revises the BES
definition.
Response: The SDT has considered the comments of the industry and determined that the point of aggregation at which dispersed
generation could have a reliability impact on the BES is at 75 MVA. The SDT has revisited Inclusions I2 and I4. The inclusions have
been broken apart to provide the clarity and granularity that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
Hydro-Quebec TransEnergie
No
Same comment as for question 1
Response: Please see response to Q1.
Cooper Compliance Corp
No
See comment to question No. 2.
Response: Please see response to Q2.
Sacramento Municipal Utility
District
No
SMUD supports the omitted Inclusion-I4 but does not fully agree with the revisions
for Inclusion-I2. SMUD is concerned regarding Inclusion-I2 that now includes a
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common BES determination for components of hydro/thermal AND wind/solar
resources. Since Inclusion-I2 establishes a 100 kV or above threshold for generators,
this draft’s current language would exclude many of the ‘dispersed resources’. If it is
determined that the ‘dispersed resource’ are subject to BES through ‘multiple stepup transformer’, the current draft language would inappropriately expand the BES
Definition to potentially include all generators regardless of voltage level when
subcategories I2a & I2b are met. Instead, to eliminate this potential expansion
SMUD urges the BES SDT to create an Inclusion that defines an element(s) as BES
where a single component(s) has the potential to removes 75 MVA of resources and
remove the ‘dispersed power producing resources’ from Inclusion-I2. The 75 MVA
threshold would eliminate the administrative and cost burden associated with
testing and documentation for ‘small-scale’ machines that are connected to sub-100
kV, are less than 3 MW, and, individually have little or no impact to reliability of the
BES. Subjecting the ‘collector system’ that typically consist of several miles of radial
34.5 kV, its system components and its dispersed generation resources to the BES
and subsequent application of NERC Reliability Standards would not provide a
proportionate impact to reliability.
Public Service Enterprise Group
No
The “Phase 1: Bulk Electric System Definition Reference Document dated April 2103
addresses I4 on pp. 15-20. These examples to not include the following in the BES:
(a) the below 100 kV collector system; (b) step-up transformers with primary and
secondary sides below 100 kV, and (c) the main GSU that connects at 100 kV to the
system. This discrepancy between traditional generation and dispersed generation
needs to be explained so that there is no discrimination between them with respect
to the BES definition.
Response: The SDT has revisited Inclusions I2 and I4. The inclusions have been broken apart to provide the clarity and granularity
that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above with:
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I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
Clarifications for components that will be included under this inclusion can be found in the Reference Document under preparation
by the SDT.
MRO NERC Standards Review
Forum (NSRF)
No
The NSRF recommends that both I2 and I4 be retained, yet reworded such as this:”I2
- Generating resource(s) and dispersed power producing resource(s), with gross
individual nameplate rating greater than 20 MVA, including the generator terminals
through the high-side of the generator step-up transformer(s) connected at a
voltage of 100 kV or above.””I4 - For generating and dispersed power producing
facilities with gross plant/facility aggregate nameplate rating greater than 75 MVA,
the bus where the aggregate generation is greater than 75 MVA and continuing thru
the high-side of the step-up transformer(s) connected at a voltage of 100 kV or
above. (Note: this does not include the individual generating resources themselves,
or the collector feeder system(s).)”The intent is to focus compliance activity at the
point where power is aggregated to the point (usually a bus) where it becomes
significant to the BES not at small (1 to 2 Mw) generators or distribution level Mw
collector systems. However, if I2 moves forward as drafted, we feel it is imperative
to launch an effort similar to the GOTO/Project 2010-07, to modify and add clarity to
standards as they would apply to a dispersed power resource. This is important, as
many of the current GO/GOP standards would be difficult and impractical to apply to
a dispersed power resource.
In addition, we recommend that interim compliance application guidance be
developed to help owners and operators of dispersed power resources understand
how to apply current standards, while also providing guidance to the auditors.
The inclusion of small individual generators will drive significant industry burden to
comply without producing any additional system reliability benefits. The inclusion of
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1 - 2 MW units as separate NERC BES elements will drive unintended consequences
for NERC standards and perhaps the wind industry as a whole as companies are
suddenly subjected to large populations of elements for standards such as PRC-004,
PRC-005, FAC-008-3, TOP-002 R14, and VAR-002 (there may be others).The reliability
issue for small generating units whether they are diesels, wind turbines, solar units,
or nuclear modules is not the risk loss of small independent individual units, it is the
common mode risk loss of significant amounts of generation at the point of
aggregation of >75MVA.
Xcel Energy
No
We do not agree that dispersed power resources should be treated the same at
traditional generators, as they are quite different in design and operation from
traditional generators and individually do not have the same impact on reliability.
For the 2 main reasons detailed below, we recommend that both I2 and I4 be
retained, yet reworded such as this:”I2 - Generating resource(s) and dispersed
power producing resources, with gross individual nameplate rating greater than 20
MVA, including the generator terminals through the high-side of the generator stepup transformer(s) connected at a voltage of 100 kV or above.””I4 - For generating
and dispersed power producing facilities with gross plant/facility aggregate
nameplate rating greater than 75 MVA, the bus where the aggregate generation is
greater than 75 MVA and continuing thru the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above. (Note: this does not include the
individual generating resources themselves, or the collector feeder system(s).)”
1) We are very concerned that the application of NERC reliability standards to
dispersed power producing resources under the proposed BES Phase II definition will
impose a major burden. The inclusions as currently drafted could even harm electric
reliability by misallocating resources away from reliability areas that are far more
likely to negatively affect BES reliability. As of the end of 2011, there were
approximately 38,000 utility-scale wind turbines operating in the U.S., many of
which are aggregated in wind projects that exceed 75 MVA in aggregate and are
connected at a common point of voltage of 100 kV or above. Including each of
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Question 4 Comment
these wind turbines and their collector systems in the BES definition would impose a
large and undue burden on wind project owners and operators, result in significant
confusion about the applicability of standards, and contribute no significant benefit
to reliability. For example, the application of PRC-005, R1, and R2 at the individual
dispersed generator unit level would require regular relay and protection system
testing at numerous places within the wind plant, potentially including the internal
circuitry of each individual wind turbine. Specifically, the applicability section 4.2.5.3
of PRC-005-2 implies that only the Protection System for the aggregating step up
transformer is included in scope, and that the Protection System for the individual
dispersed generators and aggregating systems are not. The current BES I2 includes
both the dispersed generators and the aggregating system for wind farms greater
than 75 MVA, applying PRC-005-2 requirements at 4.2.5.1 and 4.2.5.2 for generator
trip relays, and generator step-up transformers, respectively. We do not think that
application of these test requirements at the sub- 3MVA turbine level are the intent
nor the reasonable scope of a national reliability standard. We have similar concerns
with other standards including PRC-019-1, PRC-024-1, PRC-025-1, and PRC-027-1 and
how application of these requirements would conflict or confuse implementation of
this Phase II definition as applied to distributed generators and the associated
aggregating systems. As another example, TOP-002 R14 requires status reporting of
unplanned generator outages. We do not believe that the BA or TOP would benefit
from the operational notification status of any single dispersed generator at the
typical wind turbine size of 3 MVA or less.
2) A possible argument for requiring that all GO/GOP reliability standards apply to
individual wind turbines is if wind turbines were susceptible to a common mode
failure that would cause a large number of the generators within a wind plant to trip
offline within a matter of seconds. Fortunately, all wind turbines installed in the U.S.
in recent years and going forward comply with the demanding voltage and
frequency ride-through requirements of FERC Order 661A, which are far more
stringent than the ride-through requirements placed on other types of generation.
In the event of a system disturbance that causes a voltage or frequency deviation
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that would affect all generators nearly simultaneously, a wind plant would be more
likely to remain online than almost all conventional generators, and the wind plant
would likely only trip offline if the power system had collapsed to the point that
nearly all other generation had already tripped offline. As a result, there is no
compelling reliability reason for including individual wind generators and their
electrical collector systems in the BES definition.
Consumers Energy Company
Consumers Energy provides comments on the following issue raised by the Phase 2 BES definition:
(1) the changes proposed to Inclusions I2 and I4.Dispersed Power Producing Resources Should Not
Be Treated the Same as Other Generation Because They Do Not Have the Same Impact on the
BES. The Phase 2 BES definition proposes to entirely eliminate Inclusion I4 and revise Inclusion I2
to, among other changes, include dispersed power producing resources. Consumers Energy does
not agree with this change because different generating resources have different impacts on the
BES, and thus are entitled to different treatment. This change is primarily premised on the theory
that NERC should treat all power generation sources equally. While this theory sounds appealing
upon first blush, it ignores the reality that different generation sources are in fact not equal
because they differently impact the BES. In the case of dispersed power producing resources, the
potential impact on the BES of these resources is not the same as a larger power producing
resource (e.g. a 500 MW coal unit). The unexpected addition or loss of a larger generating unit
can majorly impact the reliability of the BES. The addition or loss of a single unit (e.g., a 1.4 MW
wind turbine), or even several smaller units, has little, if any, material impact on the BES. Because
of differing impacts on the BES, dispersed power producing resources are entitled to different
treatment. In addition, merely adding the phrase “and dispersed power producing resources” to
I2 significantly expands the scope of assets drawn into the BES. Under the Phase 1 definition, only
the generating units themselves were included in the BES (see, e.g., Figure I4-1 of NERC’s “Phase
1: Bulk Electric System Definition Reference Document” dated April 2013). The Phase 1 definition
did not include all of the equipment between the generator terminal through the high-side of the
step-up transformer. This exclusion of certain equipment was for good reason - dispersed power
producing resources do not individually have significant impact on the BES, and only collectively
have an impact. Under the proposed Phase 2 definition, the entire dispersed power producing
facility (e.g., an entire wind farm) will be included in the BES. While we appreciate that such an
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expansion was likely the Drafting Team’s intent, this expansion makes little sense. Dispersed
power producing resources simply do not - until aggregated - have sufficient impact on the BES to
warrant such an expansion of the scope of the BES.A better approach would be to limit the scope
of the BES to only include equipment from the point where the aggregated generation achieves
75 MVA - i.e., from the substation bus where the collector circuits aggregate to exceed 75 MVA.
As such, Consumers Energy proposes that NERC retain Inclusion I4, but change its wording to
something like this: “Dispersed power producing resources with aggregate capacity greater than
75 MVA (gross aggregate nameplate rating) utilizing a system design primarily for aggregating
capacity, from the connection point at a voltage of 100 kV or above down through the connecting
transformer to a single common point of aggregation.” This approach reasonably limits the BES
definition as applied to dispersed power producing units in a fashion proportional to their impact
on the BES.
Response: The SDT revisited Inclusions I2 and I4. The inclusions have been broken apart to provide the clarity and granularity that
the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
Standard applicability to small scale dispersed generation should be addressed through a new SAR proposed by industry.
Associated Electric Cooperative,
Inc. - JRO00088
No
The SDT needs to clarify "generator terminals" due to this current definition's
potential inclusion all the way down to individual PV cell's solder-pads and battery's
terminals. (These technically are the first electrical access-points for where
conversion takes place from other energies to electrical energy.) From a BES
Reliability aspect, the worst-case contingency is total loss of the resource at its
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greatest aggregated entry point to the BES. Therefore AECI recommends that the
SDT revert to their earlier wording. Technically, loss increments below that worstcase level, and especially for weather-sensitive solar and wind, seem no different to
System Operators than derations on any large coal-fired Units. On the other hand, if
the SDT's intent is to draft Standards in a manner to disincent renewable energy
producers from aggregating their resources to the grid in excess of 75 MVA, then
perhaps the SDT is providing the proper forcing-function here. If so, they should
show equal concern for any other type of new generating units that are sized in
excess of the same 75 MVA threshold.
SERC EC Planning Standards
Subcommittee
No
We agree in general but the SDT should review solar, fuel cell and other DC
technologies to clarify the term "generator terminals" in regards to the PRC
standards.
Additionally, clarification should be made that limits inclusion to the greatest
contingency loss which is the step-up transformer to the grid.
South Carolina Electric and Gas
No
We agree in general but the SDT should review solar, fuel cell, and other DC
technologies to clarify the term "generator terminals" in regards to the PRC
standards.
Additionally, clarification should be made that limits the inclusion to the greatest
contingency loss, i.e. the step up transformer to the grid.
SERC Reliability Corporation
The inclusion language uses the words "generator terminals". "Generator terminals" are not a
good demarcation point for defining a bright-line for the collector system that represents faciltites
that are necessary for reliable operation. These words will not be clear with some power
producing resources (wind, solar, low-head hydro, etc.). The SDT should review solar, fuel cell and
other DC technologies to clarify the term “generator terminals” as it relates these types of
generating resources. An alternative may be to define a proxy for generating resource "generator
terminals" (may be made up of multiple individual resources) by the connection point below the
step-up transformer where aggregate capacity exceeds the individual unit registration threshold
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of 20MVA
Response: The SDT has revisited Inclusions I2 and I4. The inclusions have been broken apart to provide the clarity and granularity
that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources
aggregate to greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
With these changes, the ambiguity caused by the term “generator terminals” has been removed.
Modesto Irrigation District
No
Response: Without a specific comment, the SDT is unable to respond.
Colorado Springs Utilities
Yes
1. Define “dispersed power producing resources."
Response: The SDT feels that the note included in the definition and within the reference document adequately explain the intent
of “dispersed power producing resource and therefore a definition is not required.
Georgia Transmission
Corporation
Yes
Because of the addition of “dispersed power producing resources” to I2...GTC
believes it’s more appropriate to replace the term “generator” with “resource” in
the following phrase: ..."including the generator terminals through the high-side..."
Independent Electricity System
Operator
Yes
In general we agree with these changes and propose the following alternative
language for more clarity:’ Generating resource(s) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above, and dispersed power producing resources connected at a common point
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at a voltage of 100 kV or above with;’
Idaho Power Company
Yes
What is lost in deleting I4 per se and rolling up "dispersed power producing
resources" into I2 is the distinctive characteristic of dispersed power producing
resources of "utilizing a system designed primarily for aggregating capacity,
connected at a common point ". Without making this distinction, the "dispersed
power producing resources" are just another generating resource. Therefore, there
is no need to add "dispersed power producing resources" to I2 if I4 is deleted per se
as suggested. At the same time, if the distinctive characteristic of dispersed power
producing resources of "utilizing a system designed primarily for aggregating
capacity, connected at a common point " was also rolled up to I2, then why delete I4
at all? IF the recommendation to delete I4 and modify I2 as presented in the Project
2010-17 draft 1 is the decision of the Project Team, we would recommend further
adding "utilizing a system designed primarily for aggregating capacity, connected at
a common point" to clarify "dispersed power producing resources". In conclusion,
we would not be in favor of making the changes that are the subject of Q4.
Response: The SDT has revisited Inclusions I2 and I4. The inclusions have been broken apart to provide the clarity and granularity
that the industry has requested.
I2 – Generating resource(s) and dispersed power producing resources, including the generator terminals through the high-side
of the step-up transformer(s) connected at a voltage of 100 kV or above with:
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the point where those resources aggregate to
greater than 75 MVA , connected atto a common point of connection at a voltage of 100 kV or above.
US Bureau of Reclamation
Yes
Reclamation agrees with the addition of the term "dispersed power resources" in I2.
However, Reclamation believes that certain aspects of Inclusion I2 are quite
problematic. We have included comments on outstanding issues in I2 related to
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Question 4 Comment
generation step up transformers (GSUs) in response to Question 6.
Response: Please see response to Q6.
Ameren
Yes
We request that the SDT renumber the Inclusions to yield I1 through I4 (i.e. move
the I5 language to I4), as we believe this will be clearer than having a blank or
unused I4.
Response: The SDT has reinstated the I4 inclusions and therefore renumbering is not required.
American Transmission Company
Yes
ATC has no comments.
NV Energy
Yes
Yes, this was an efficient change to consolidate the two inclusions and in the long
run, will eliminate confusion and possible inconsistency.
Dominion
Yes
Tennessee Valley Authority
Yes
SPP Standards Review Group
Yes
Pepco Holdings Inc & Affiliates
Yes
DTE Electric
Yes
IRC Standards Review Committee
Yes
PPL NERC Registered Affiliates
Yes
Arizona Public Service Company
Yes
Southwest Power Pool Regional
Yes
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Entity
Central Lincoln
Yes
FirstEnergy
Yes
Manitoba Hydro
Yes
Orange and Rockland Utilities Inc. Yes
Duke Energy
Yes
ISO New England Inc.
Yes
Tri-State Generation and
Transmission, Inc.
Yes
American Public Power
Association
Yes
Response: Thank you for your support.
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5. The SDT has made a number of clarifying changes to language in response to industry comments as follows: (a) I1: Change ‘under’
to ‘by application of’; (b) I2: Split out the inclusion to clearly show that it is an ‘or’ condition; (c) I5: Add ‘unless excluded by
application of Exclusion E4’; (d) E3: Change ‘… retail customer Load…’ to ‘retail customers’; (f) E3c: Change ‘… a monitored Facility
of a …’ to ‘… any part of a…’; (g) E4: Add the phrase ‘installed for the sole benefit of’. Do you agree with these changes? If you do
not support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions (using the letter of the change) in your comments.
Summary Consideration: Several commenters attempted to re-open items that were decided and approved in Phase 1 and for which no
changes are being made in Phase 2. The SDT notes that those issues raised were previously decided by the Commission in its related
Orders, and were not a topic for reconsideration in Phase 2.
The SDT made the following changes due to industry comments:
I2 a) - Gross individual nameplate rating greater than 20 MVA,. ORr,
E4 - Reactive Power devices installed for the sole benefit of a retail customer(s).
Organization
South Carolina Electric and Gas
Yes or No
No
Question 5 Comment
Change the wording in E-4 from "installed" to "operated".
Change the wording in E-3c from "part" to "element".
Change "permanent Flowgate" to "permanent Reliability type Flowgate". The
Eastern Interconnection Book of Flowgates differentiates between "informational"
and "Reliability" type Flowgates.
SERC EC Planning Standards
Subcommittee
No
E4 change the word "installed" to "operated".
E3c change "part" to "element" and add "Reliability type" to the statement:
permanent Reliability type Flowgate. The rationale is that the Eastern
Interconnection Book of Flow gates contains some entries flagged "informational"
and this would differentiate between the flow gates (reliability versus
informational).The comments expressed herein represent a consensus of the views
of the above named members of the SERC Planning Standards Subcommittee (PSS)
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only and should not be construed as the position of the SERC Reliability Corporation,
or its board or its officers.
Response: Regarding Exclusion E4 - the SDT agreed that “installed” is the proper term as it best describes the intent of the use of
reactive devices, however, as a result of consideration of other Exclusion E4 comments, the SDT has modified Exclusion E4 to read:
E4 - Reactive Power devices installed for the sole benefit of a retail customer(s).
Regarding Item (g) - the SDT notes that the issue raised regarding “permanent Flowgate” was previously decided by the Commission
in its related Orders, and was not a topic for reconsideration in Phase 2. The SDT reconfirms that the description “… any part of …”
properly characterizes the intent for Exclusion Ec3. Reliable operation of the system requires operator situational awareness of all
permanent Flowgates in order to balance the physical network constraints against any commercial considerations that may occur in
the network. This need for situational awareness requires knowledge of “any part of” a permanent Flowgate.
Duke Energy
No
Duke Energy believes the SDT should consider changing the language of E4 to
“Reactive Power devices installed for the benefit of a retail customer(s).”
Northeast Power Coordinating
Council
No
For Exclusion E4 Reactive Devices - The drafting team agreed that use, and not
ownership, should dictate the disposition of reactive devices. Reactive devices used
to support retail customer loads, and not used in day-to-day operations for BES
voltage control for either steady state or contingency operations, may be excluded
from the BES regardless of ownership. Devices need not be owned by “a retail
customer” as a prerequisite for exclusion. Reactive devices owned by others, such as
a Transmission Owner, and installed solely for the benefit of retail customer load
should also qualify for exclusion. The proposed wording still carries remnants of the
previous retail customer concept. It refers to a singular customer. Yet, reactive
devices may be installed to benefit a group of retail customers collectively referred
to as retail load. Suggest revising E4 to either read:E4--Reactive Power devices
installed for the sole benefit of retail customers. orE4--Reactive Power devices
installed for the sole benefit of retail load.
PacifiCorp
No
PacifiCorp does not agree with certain of the SDT’s clarifying changes enumerated
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above, for the following reasons: o Item (b): rationale provided in response to
question 4 above; and
o Item (d): Reactive Power devices are often installed on substation busses less than
100 kV for the sole benefit of the retail customers of the utility. If a substation or
substation bus is excluded from the BES through either Exclusion 1 or Exclusion 3
and is installed for the sole benefit of the retail customers, then that device should
also be excluded from the BES. PacifiCorp offers the following suggested wording
for Exclusion E4 for the SDT’s consideration: Reactive Power devices installed for the
sole benefit of retail customers.
Response: The SDT agreed to modify Exclusion E4 to read:
E4 - Reactive Power devices installed for the sole benefit of a retail customer(s).
Self
No
It is never possible to determine whether a reactive device is for the "sole benefit"
of retail customers. The presence of a reactive device may benefit the retail
customer from a rates perspective or a local voltage perspective, but the presence
of the reactive device, no matter where it is located, even at the distribution level,
also provides system wide BES/BPS benefits.
Response: The SDT notes that the issue raised was previously decided by the Commission in its related Orders, and was not a topic
for reconsideration in Phase 2. No change made.
ACES Standards Collaborators
Yes
(1) In general, these are clarifying changes and we are supportive of them.
However, one change is not a clarifying change but is in fact a substantive change.
Changing “a monitored Facility of a permanent Flowgate...” to “any part of a
permanent Flowgate...” is not a clarifying change but is in fact a substantive change.
Consider that a Flowgate contains a monitored facility and often a contingent
Facility. The contingent Facility will now be included whereas it was not previously
included. In the end, these contingent Facilities probably will already be included by
the bright line 100 kV threshold as they are usually a larger facility than the
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Question 5 Comment
monitored facility. However, this should not be represented as a clarifying change.
(2) “OR” should be “or”.
Response: Regarding Item (g) -the SDT reconfirms that the description “… any part of …” properly characterizes the intent for Ec3.
Reliable operation of the system requires operator situational awareness of all permanent Flowgate types in order to balance the
physical network constraints against any commercial considerations that may occur in the network. This need for situational
awareness requires knowledge of “any part of” a permanent Flowgate. No change made.
Regarding Item (d) – the SDT capitalized “OR” in the posting to highlight the change. Inclusion I2a has been changed to read:
I2 a) - Gross individual nameplate rating greater than 20 MVA,. ORr,
New York Power Authority
Yes
No comments.
American Transmission Company
Yes
No comments.
Public Utility District No.1 of
Snohomish County
Yes
The Public Utility District No.1 of Snohomish County supports the SDT's approach.
Idaho Power Company
Yes
We would be in favor of making the changes that are the subject of Q5.
Associated Electric Cooperative,
Inc. - JRO00088
Yes
Dominion
Yes
MRO NERC Standards Review
Forum (NSRF)
Yes
Tennessee Valley Authority
Yes
SPP Standards Review Group
Yes
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Cooper Compliance Corp
Yes
City of Tacoma
Yes
Pepco Holdings Inc & Affiliates
Yes
DTE Electric
Yes
Iberdrola USA
Yes
IRC Standards Review Committee
Yes
PPL NERC Registered Affiliates
Yes
North American Generator
Forum Standards Review Team
Yes
Hydro One Networks Inc.
Yes
Arizona Public Service Company
Yes
Southwest Power Pool Regional
Entity
Yes
Colorado Springs Utilities
Yes
Transmission Access Policy Study
Group
Yes
Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Yes
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Yes or No
Question 5 Comment
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
US Bureau of Reclamation
Yes
Central Lincoln
Yes
FirstEnergy
Yes
Hydro-Quebec TransEnergie
Yes
Wisconsin Public Service / Upper
Peninsula Power
Yes
Public Service Enterprise Group
Yes
Manitoba Hydro
Yes
Sacramento Municipal Utility
District
Yes
Occidental Energy Ventures Corp. Yes
American Electric Power
Yes
Georgia Transmission
Corporation
Yes
Independent Electricity System
Yes
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Question 5 Comment
Operator
Ameren
Yes
ISO New England Inc.
Yes
NV Energy
Yes
American Wind Energy
Association
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
American Public Power
Association
Yes
MidAmerican Energy
Yes
Response: Thank you for your support.
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6. Are there any other concerns with this definition that haven’t been covered in previous questions and comments?
Summary Consideration: Several commenters raised issues concerning the implementation plan with respect to jurisdictional
boundaries. After conferring with NERC Legal, the SDT has revised the jurisdictional language.
Several commenters raised concerns about the SDT treatment of the thresholds that reside within the BES definition. The results of the
NERC Planning Committee’s (PC) evaluation of the various thresholds contained in the BES definition were presented to the SDT for
consideration in developing revisions to the definition in Phase 2. The PC determined that all thresholds should remain at the statusquo. The SDT, based on the recommendations from the PC, has opted to retain the original thresholds in the definition.
The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the
Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the
bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A,
paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not be
included in the bulk electric system, unless determined otherwise in the exception process.”
Several commenters expressed concerns related to the power flow associated with local networks and the methodology recommended
to determine the amount of actual power flow. Exclusion E3b defines an absolute value associated with power flow from a local
network to maintain the bright-line concepts of the definition. The SDT has determined that the best method to quantify the amount of
power flow associated with a local network is to evaluate the hourly integrated flows over the most recent 2 year period. Although this
allows for some amount of flow from the local network this is considered to be inconsequential when considering the impact of minimal
flows over very short periods of time.
Numerous commenters provided comments on the contents of the BES Definition Reference Document. The SDT appreciates the
comments concerning the BES Definition Reference Document; however this comment period concerns the Phase 2 revision of the BES
definition. As the SDT gains more certainty in final outcome of the definition development, the BES Definition Reference Document will
be updated and posted for industry comment.
Organization
Yes or No
Manitoba Hydro
No
Question 6 Comment
(1) Although Manitoba Hydro is in general support of the changes, we would like to
include the following clarifying comment: Implementation Plan, Effective Dates replace the words “go into effect” with “become effective”. Moreover, append the
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Question 6 Comment
wording, after “applicable regulatory approval”:”, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.” Prior to the
wording “In those jurisdiction....”. The same changes should be made to the first
sentence in the Effective Date Section of the proposed Definition document.
Response: After conferring with NERC Legal, the SDT has revised the jurisdictional language.
This definition shall become effective on the first day of the second calendar quarter after applicable regulatory approval. In
those jurisdictions where no regulatory approval is required the definition shall go into effectbecome effective on the first
day of the second calendar quarter after Board of Trustees adoption or as otherwise made effective pursuant to the laws of
applicable governmental authorities.
Cogeneration Association of
California
Yes
There are several issues regarding industrial facilities that should be addressed in
Phase 2. Including the facilities of any individual industrial customer in the BES and
making them subject to NERC standards and enforcement unreasonably expands a
program designed to regulate utilities. This shifts the responsibility for utility
functions to individual, non-jurisdictional entities, including industrial customers, and
customer generators. It is ironic that these entities built generation for increased
reliability of service to their installations - not to serve the grid - and in many cases to
substitute for the less-than-reliable utility grid service. The comments to FERC on
the NOPR and in the requests for rehearing raised several issues with regard to
industrial facilities that FERC deferred to Phase 2. These comments include those
advocating exemption of industrial facilities with power flowing through and out to
the grid, such as those asserted by Dow and Valero. The issues associated with
industrial customers employing self-generation to serve on-site load should
appropriately be included in this Phase 2 effort. To address these issues, CAC, EPUC
and CLECA propose four development initiatives within Phase 2:
o First, there should be an additional exclusion from the bright-line test:
oIf the
element is not owned or operated by a public utility regulated by a state authority as
a common carrier, or by FERC as a public utility, there is a presumption that the
element is not part of the Bulk Electric System (BES);
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Question 6 Comment
o For any element that is not a public utility, and that is asserted to be material to
the reliability of the BES, the burden is on the regional entity or the interconnected
public utility to demonstrate that the non-public utility customer facilities are an
essential and material part of the BES.
o This shift in burden is important because of the difficulty for an individual industrial
customer/self-generator to obtain the necessary data to model its impact on grid
reliability. Confidential modeling of power flows or information of other customers’
usage is not going to be provided by the utilities to customer generators as market
participants.
o Second, there should be a functional test specified for determining “material
impact” to grid reliability, to facilitate the exclusion of elements. FERC in Order 743
and subsequent orders finds that a functional test of “no material impact” may not
be sufficient to identify elements that are “necessary to operate the system.” In
footnote 35 of the April 18 rehearing order, FERC indicates that NERC has the option
to develop such a test. A test of “no material impact and unnecessary to operate the
system” should be developed, particularly to allow the exclusion of industrial
facilities never intended to support grid reliability.
o Third, NERC should further analyze the issue of power flowing out of a local
network. Industrial facilities have often constructed two interconnections to the
grid. This has typically been done to ensure reliability of service to the end-use
industrial facility, but in doing so, it may also inadvertently provide a path for flows
of small amounts of power through the interconnection points back to the grid. The
purpose of the dual interconnection is reliability and not to provide transfers of
energy across the bus. The transmission operator is not likely to depend on the
interconnection point as a means to provide grid service to other customers or to
model that service in its transmission planning studies. NERC’s technical studies
should provide FERC with some criteria for exempting industrial facilities with singlesourced dual feeds that are not intended to support the grid as a transfer path for
power and are not modeled as such by the Transmission Planner or Balancing
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Yes or No
Question 6 Comment
Authority.
o Fourth, NERC, under the E-1 exclusions for radial lines, should not unilaterally
dismiss the exclusion for radial lines if the industrial customer has more than one
line servicing its facility. Most large manufacturing facilities are served by multiple
feeds to maximize service reliability. This is done because the load is more reliable
than the lines serving the facility. A refinery, chemical plant or other 24/7 facility
cannot afford to operate without redundant power lines. Dual feeds, typically from
the same utility substation, are constructed to provide benefits to both the utility
and the large industrial customer. With that configuration the utility can maintain
its revenue stream while performing routine maintenance without shutting-in a
facility. In the case of a refinery, if it were forced to shut down during routine line
maintenance, it can take up to several days to safely shut down and even longer to
start up. By having redundant lines, often on the same poles, a facility can save
millions of dollars in shut down costs and other related expenses. It would be
commercially negligent in many cases for large customers not to have the
redundancy. Utilities can provide increased reliability and perform repairs more
safely with the redundant lines. In no way does the fact that two lines providing
service to a single large industrial facility, typically from the same utility source,
change the characteristic of that service as being anything more than a radial line
feed.
Response: The BES definition is a bright-line ‘component’ based definition that does not take into account ownership or operational
responsibilities of subject facilities and when appropriately applied produces consistent results on a continent-wide basis. In the
event that the BES definition designates an Element as BES that an entity believes is not necessary for the reliable operation of the
interconnected Transmission network, the ERO Rules of Procedure exception process may be utilized on a case‐by‐case basis to
either include or exclude an Element. The SDT recognizes that there is a certain level of burden on the entity when utilizing the
exception process, however, a ‘blanket’ exclusion based on facility ownership is contradictory to the fundamental tenets that are the
basis for the BES definition. No change made.
During Phase 1 of the project the SDT developed a document which provides guidance to an entity on the development of technical
justification which can support an exceptions request. This document is titled: Detailed Information to Support an Exception Request
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and is currently available on the BES definition project page. During the development of this document the SDT explored the
possibility of a single functional test that would result in identifying facilities that have no material impact on, and are unnecessary
to operate, the interconnected Transmission network. The SDT determined that no single parameter was by itself solely indicative of
that facility’s material impact on or whether it is necessity to operate the interconnected Transmission network. Therefore, the SDT
determined that a single functional test was not a feasible solution for defining the BES nor were the results of a single functional
test adequate justification for granting exclusion through the exceptions process. No change made.
Industrial customers with multiple feeds from the interconnected Transmission network to their facilities (providing there is a
looped facility connecting these feeds) are subject to the criteria established by Exclusion E3 when analyzing for potential exclusion
from the BES. In the event that the BES definition designates an Element as BES that an entity believes is not necessary for the
reliable operation of the interconnected Transmission network, the ERO Rules of Procedure exception process may be utilized on a
case‐by‐case basis to either include or exclude an Element. No change made.
Independent Electricity System
Operator
Yes
1) NERC must ensure that any new or changes to standards as a result of FERC
directives that apply to load reliability and load supply continuity are limited to the
FERC jurisdiction only. In Canada, local load reliability requirements are under the
authority of local regulators such as the Ontario Energy Board in Ontario.
2) Implementation Plan may result in a conflict with Ontario regulatory practice with
respect to the effective date of the standard. It is suggested that this conflict be
removed by appending the effective date wording, after “applicable regulatory
approval” in the Effective Dates Section of the Implementation Plan, to the following
effect:”, or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.” prior to the wording “In those jurisdiction....”.The same
changes should be made to the first sentence in the Effective Date Section of the
proposed Definition document.
3) In our opinion, SDT has correctly crafted the language in E1 and E3 in the
approved definition. To address some of the FERC concerns, it may be simpler and
clean to introduce a new inclusion “I” for sub 100kV system(s) that are used for bulk
power transfer (not a sink) across the BES from one area to the other.
Response: 1). Jurisdictional concerns between regulatory authorities are beyond the scope of this project and are not the
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responsibility of the SDT to resolve. The proper channels exist to address these concerns; however they reside outside of the
Standard Development Process.
2). After conferring with NERC Legal, the SDT has revised the jurisdictional language.
This definition shall become effective on the first day of the second calendar quarter after applicable regulatory approval. In
those jurisdictions where no regulatory approval is required the definition shall go into effectbecome effective on the first
day of the second calendar quarter after Board of Trustees adoption or as otherwise made effective pursuant to the laws of
applicable governmental authorities.
3). The analysis of sub-100 kV loops associated with the evaluation of Elements under the E1 and E3 exclusions is used as a ‘qualifier’
for the potential exclusion of the Elements that operate at or above 100 kV. The failure to not meet the ‘bright-line’ criteria
established by Exclusions E1 and E3 does not result in the inclusion of the sub-100 kV loops in the BES. Order 773, paragraph 155
states: “Thus, the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV
elements in figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the
Commission in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems
and local networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
Therefore, an Inclusion for sub 100kV system(s) that are used for bulk power transfer (not a sink) across the BES from one area to
the other would not be appropriate.
Central Lincoln
Yes
1) Central Lincoln remains concerned regarding the limits imposed by b) on local
networks. We note that by order 773A, FERC considers this limit to be absolute with
no allowance for minimal reverse flows for even brief periods under multiple
contingencies. While denying rehearing on this issue, FERC specifically invited Phase
2 to adjust this outcome in paragraph 79 of the order. We also note that the BES
Definition Reference would allow very brief flows out of a local network as long as
the integrated hourly flow was still into the local network. FERC, however, did not
rule on the Reference document, only the definition itself. Even if FERC did allow the
language of the Reference document, the first multiple contingency event that
results in out flow or through flow for the better part of an hour would cause an
excluded network to become immediately included, and subject to standards
without any implementation period (assuming 24 months had passed from the
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effective date of the definition). The Planning Committee provided several options
to SDT on this matter. We understand the SDT’s reluctance to impose system studies
on what is intended to be a simply determined bright line criterion, but the present
exclusion is not very useful. Central Lincoln would support using a fixed two year (or
longer) window rather than the most recent two year sliding window suggested in
the reference document. However it is determined, it should be included within the
approved definition so that the reference document disclaimer does not apply.
2) Non-retail generation still lacks a definition to be approved by NERC and FERC,
even though this this item was specifically included in the approved SAR. We note
that the term is defined in the Reference Document where the disclaimer stating it is
not an official position of NERC ensures this definition has little value. While the
Reference Document states “Non-retail generation is any generation that is not
behind a retail customer’s meter,” we continue to hear it defined without the “not.”
It is very important that entities and regions have a common understanding of the
term, and ask the team to include its definition within the BES definition.
Response: 1. Although Exclusion E3b defines an absolute value associated with power flow from a local network to maintain the
bright-line concepts of the definition. The SDT has determined that the best method to quantify the amount of power flow
associated with a local network is to evaluate the hourly integrated flows over the most recent 2 year period. Although this allows
for some amount of flow from the local network this is considered to be inconsequential when considering the impact of minimal
flows over very short periods of time. The 2 year period is recommended as a sliding time frame to account for system changes that
periodically occur on any electrical system. For instances that result in a change of BES classification of a subject local network, the
entity should contact it’s Regional Entity for the Regional practices that address the situation in question. The disclaimer in the BES
Definition Reference Document is under the purview of NERC Legal and is not under the control of the SDT.
2. The Phase 2 SAR identified the following in regards to clarification associated with non-retail generation.
Provide improved clarity to the following: The use of the term “non-retail generation”
The SDT provided the following clarification concerning non-retail and retail generation in the BES Definition Reference Document.
Non‐retail generation is any generation that is not behind a retail customer’s meter. Retail generation is behind the meter
generation with all or some of the generation serving the on-site Load.
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Wisconsin Electric
Yes
Question 6 Comment
1. Wisconsin Electric is concerned that the drafting team has not considered the
potential impacts of the proposed definition on other standards or their
requirements. For this reason the definition should be rejected until such time as
adequate consideration has been given to such inter-dependencies and potential
impacts on various standards which assume a BES definition for their related
requirements.
2. Wisconsin Electric participated in the June 26th webinar and during the webinar it
was stated that the PRC and CIP standards have unique and unrelated BES bright line
criteria. The final definition of BES must apply to all standards in a clear and
unambiguous manner. Under the CIP Version 5 standards, clarification is needed to
determine whether wind turbine controls become “Low Impact BES Cyber Systems”
under the bright line criteria.
3. Wisconsin Electric agrees with the NAGF comments to Question #6 Part 1.4.
Clarification should be provided that the BES definition pertains only to normal
operating conditions.
Response: 1). The DBES SDT conducted a review of applicability of Reliability Standards. The review consisted of the Reliability
Standards that are applicable to the Transmission Owners (TO), Generator Owners (GO), Transmission Operators (TOP), and
Generator Operators (GOP). The review was based on the premise that the applicability of Reliability Standards is limited to BES
Elements unless otherwise stated in the ‘Applicability’ section of the standard or identified in the individual requirements. The
review was conducted to: (1) Assess the impact of the revised BES definition on the current applicability of the subject Reliability
Standards, and, (2) Identify areas where the applicability could be improved from a clarity perspective and (3) Assess the proper
application of BPS vs. BES. The results of this analysis were forwarded to the NERC Standards Committee for consideration: (1) The
BES SDT found no issues that were identified as an immediate concern based on the revised definition of the BES, therefore the BES
SDT did not develop any supporting draft SARs or potential redline changes; (2) The BES SDT identified several areas where the
clarity of the applicability could be improved. These issues were documented and provided to the NERC SC with the expectation is
that these issues would be added to the ‘Standards Issues Database’ for consideration by future SDTs. Additionally, the results of the
BPS vs. BES assessment were provided to the NERC SC, again with the expectation is that these issues would be added to the
‘Standards Issues Database’ for consideration by future SDTs.
2). The applicability of Reliability Standards is limited to BES Elements unless otherwise stated in the ‘Applicability’ section of the
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standard or identified in the individual requirements. The applicability of the CIP Standards is beyond the scope of the DBES SDT’s
responsibilities.
3). See response to the comments provided by the North American Generator Forum.
Colorado Springs Utilities
Yes
1. We appreciate the clarifying language change of E3c. Monitoring status
should not necessarily include or exclude a Facility from the BES. We want to
make sure that we do not discourage or hamper monitoring of facilities by
incorrectly involving Facilities that are “monitored” but do not have an effect
on the BES into this definition or other NERC standards.
Response: Thank you for your support.
Associated Electric Cooperative,
Inc. - JRO00088
Yes
AECI recommends for E3c: REPLACE: "Flowgate", WITH: "reliability type Flowgate",
RATIONALE: The Eastern Interconnection's Book of Flowgates contains both
"(Informational)" and "(Reliability)" types of Flowgates. Line-item example excerpts:
"/ Type: PTDF (Informational)" -versus- "/ Type: PTDF (Reliability)". AECI
believes only elements from the reliability type FGs could be of concern here.
Response: The SDT believes that the reliable operation of the interconnected transmission system requires operator situational
awareness of any and all parts of permanent flowgates in order to adequately provide for reliable operation. Hence, the presence
of any part of a flowgate should preclude the application of the E3 Exclusion. Accordingly, the SDT is making no changes to this
revised language of Exclusion E3(c).
Idaho Power Company
Yes
Another issue that came up, relative to Q4, is that even with the clarification of the
"dispersed power producing resources", the question remains as to how to treat
new and existing, large and small generator sources connected to feeders that
connect to the same BES bus. Do we need to keep a running total of the installed
aggregated capacity and then, once the 75MVA aggregate threshold is reached,
change the BES classification of all these previously non-BES units? It would be hard
to argue that these are NOT “utilizing a system designed for aggregating capacity”.
Response: Entities are required to evaluate their respective systems to identify scenarios where the scope of what is considered to
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be BES has been changed, for example, situations such as new construction, reconfiguration, decommissioning of facilities, etc. If
system topology changes dictate that the scope of the BES has changed and newly identified Elements are now considered to be
BES, the entity has the responsibility to inform the Regional Entity of this change (See ERO Rules of Procedure, Section 500 –
Organization Registration and Certification, Paragraph 501, Part 1.3.5).
The BES Reference Document provides specific examples that address this concern (See Figures I2-5 and I2-6). In these examples the
use of multiple transformers and interconnecting bus work is described for various scenarios. Figure I2-5 describes a generation
resource that utilizes multiple step-up transformers and interconnecting bus work that is installed for the sole purpose of stepping
up the voltage output of the generator to a voltage of 100 kV or above. Based on this scenario the generation resource is considered
to be a BES Element. Figure I2-6 describes a generation resource that utilizes multiple step-up transformers and interconnecting bus
work that serves two purposes: first, the interconnecting bus work serves Load at a voltage level <100 kV, and second provides a
connection of the generation resource to a voltage level > 100 kV. Based on this scenario the generation resource is not considered
to be a BES Element.
Xcel Energy
Yes
As explained under question 4, we feel that dispersed power resources should not
be treated the same as traditional generating resources. However, if I2 moves
forward as drafted, we feel it is imperative to launch an effort similar to the
GOTO/Project 2010-07, to modify and add clarity to standards as they would apply
to a dispersed power resource. This is important, as many of the current GO/GOP
standards would be difficult and impractical to apply to a dispersed power resource.
In addition, we recommend that interim compliance application guidance be
developed to help owners and operators of dispersed power resources understand
how to apply current standards, while also providing guidance to the auditors.
Response: The SDT recommends to the commenter to complete and submit a Standard Authorization Request (SAR) identifying the
concerns raised here and the proposal to initiate a project to address the concerns. Guidance on any interim compliance applications
is beyond the scope of this project and the responsibilities of the SDT.
Dominion
Yes
Based on FERC orders 773 and 773-A and NERC’s response to those orders,
Dominion no longer sees the value of Note 1 under E1 and suggests it be removed.
Further Dominion believes the industry has typically considered the terms ‘network’
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and ‘contiguous’ to exclude elements or facilities that contain a normally open
device (switch, breaker, disconnect, etc) between them. Although Dominion initially
thought it understood the meaning of the BES definition, our attendance at seminars
in June and the attempted application of the BES definition to the Dominion system
has led to some confusion.
Please provide additional clarity on the Local Network exclusion E3b. The BES
definition is vague and ambiguous as to whether flow out of the network requires
study under N-0, N-1, N-2, etc. conditions. The SDT has stated that one does not
have to perform loadflow studies to determine a local network. It has also stated in
the guidance document that two years of historical flow data may be used to make
the determination. Both of these imply the BES is to be evaluated under an N-0
situation. On the other hand the SDT has stated “This definition, as approved, clearly
specifies no outward flow from the local network under any conditions and for any
duration.” {comments on guidance document October 4, 2012 through November
5, 2012}. This implies that some type of contingency analysis must be performed.
Consider as an example, Figure E3-3 of the April 2013 Guidance document. With all
lines in service as depicted, the 138 kV system is undoubtedly a local network.
However, if the definition truly means “under any condition” then one could select
an a set of <300 kV and 138 kV contingencies that would force power through the
138 kV and then back onto the BES since there is no alternate path. This would
negate the assertion that this is non-BES and excludable. We doubt if that is the SDT
intent and believe the definition as written is silent on the contingency issue. Clearly
there needs to be a practical limit to how many contingencies one would need to
take or clarificiation whether contingencies should be taken at all. Evaluation at all
load levels, all credible dispatches with a variety of contingencies is tremendously
burdensome. Our preference would be to evaluate with all lines in service (N-0)
since this would insure maximum buy-in from stakeholders. E3b should read :E3b)
“Power flows only into the LN and the LN does not transfer energy originating
outside the LN for delivery through the LN under normal (non-contingency)
conditions...”
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The Guidance document, as revised for phase II, is important to understand the BES
definition. It introduces concepts not explicitly mentioned in the BES definition
(“The SDT’s intent was that hourly integrated power flow values over the course of
the most recent two-year period would be sufficient to make such a
demonstration.”) However, the guidance document does not have legal standing
since it is not FERC approved. We think it should go through the interpretation
process for stakeholder review and be integrated into the BES definition with FERC
approval.
Response: The SDT feels that Note 1 under Exclusion E1 provides necessary clarity to the exclusion and has determined that the note
will be retained.
The BES definition is a component-based definition that applies for all operating scenarios (normal operating conditions and
contingency conditions). To establish a bright-line aspect to the Exclusion E3 criteria, the SDT developed Exclusion E3b which
addresses the power flow at the local network interfaces. This ‘operational’ criterion was necessary to show that the local network
would have minimal impact to the surrounding interconnected Transmission network under the potential scenarios the local
network has experienced during the most recent two-year period. An entity who determines that all or a portion of its Facilities
meet the local network exclusion should be able to demonstrate, by inspection of actual system data, that flow of power is always
into the local network at each point of interface with the BES at all times. The SDT’s intent was that hourly integrated power flow
values over the course of the most recent two‐year period would be sufficient to make such a demonstration and that further study
analysis of the local network should be reserved for the BES Exceptions Process. No change made.
The BES Reference Document provides a descriptive explanation of the application of the BES definition that supports the
understanding and interpretation of a definition. The SDT has developed BES Definition Reference document in accordance with the
Standard Process Manual Section 11.0: Process for Approving Supporting Documents. The SDT will be updating the document to
reflect that revisions made to the BES definition during Phase 2 of the project. If the commenter wishes to pursue a formal
interpretation of the BES definition, the Standard Process Manual provides the procedural steps that are necessary (see Section 7.0:
Process for Developing an Interpretation).
Consumers Energy Company
Yes
Consumers Energy provides comments on the following issue raised by the Phase 2
BES definition: 2) a recommended change to Inclusion I3.Inclusion I3 Should Exclude
Blackstart Resources Connected to the BES Only On A Very Limited Basis The Phase 2
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BES definition (and the Phase 1 BES definition) in Inclusion I3 provides that all
Blackstart Resources identified in the Transmission Operator’s restoration plan are
part of the BES. NERC should modify Inclusion I3 to exclude Blackstart Resources
that are only connected to the BES on a very limited basis.
NERC should impose requirements on an asset proportional to the asset’s impact on
the BES. As such, assets that have little-to-no impact on the BES should be subject to
only minimal requirements. In the case of Blackstart Resources, some such
resources have extremely little impact on the BES during a typical day. For example,
some gas peaker units are only connected to the BES for less than 24 hours in a year
because they are used only during extreme weather conditions or when the system
is actually “black.” Given their low impact on the BES, NERC should regulate these
units in a way proportional to their limited use. Therefore, Consumers Energy
proposes that NERC modify Inclusion I3 to cover “Blackstart Resources identified in
the Transmission Operator’s restoration plan, unless such a resource is connected to
the Bulk Electric System for less than 24 hours per year.” This modification would
provide the regulation in proportion to these units’ impact on the BES.CONCLUSION:
WHEREFORE, Consumers Energy Company urges NERC and the Standard Drafting
Team for Project 2010-17 to reflect on these comments in developing the proposed
Phase 2 BES definition.
Response: Blackstart Resources are defined in the NERC Glossary of Terms Used in Reliability Standards and identified in the NERC
Statement of Compliance Registry Criteria as a criterion for functional registration. These resources were the basis for the
development of Inclusion I3. The proposed revision would establish criterion that detracts from the bright-line aspect of the
definition. The SDT feels that under the situations described by the commenter, the best place to address the commenter’s concerns
is through the potential revision to the ‘Applicability’ of the appropriate Reliability Standards.
Duke Energy
Yes
Duke Energy believes that ambiguity exists between the industry and FERC within
the language of E1 regarding “single point of connection”. See paragraph 138 and
142 of Order 773. The language “single point of connection” in E1 should be revised
for clarity. If E1 is edited, the change may impact the terminology used (“multiple
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points of connection”) in E3.
Response: Based on the development record of the Phase 1 definition and the ‘Commission Determination’ from Order 773
(paragraph 142), the SDT feels that the language in Exclusion E1 regarding ‘single point of connection’ is sufficiently clear to ensure
consistent application of the BES definition on a continent-wide basis. Additionally the BES Reference Document provides further
explanation of what constitutes a ‘single point of connection’. Section III.1, BES Exclusion E1, Part ‘Single point of connection’ states:
“For example, the start of the radial system may be a hard tap of the Transmission line, or could be the tap point within a ring or
breaker and a half bus configuration. No change made.
SPP Standards Review Group
Yes
E3 has been changed in response to a FERC directive to remove the lower bound for
LNs of 100 kV. While the removal does directly address the directive from FERC, the
removal of the 100 kV lower limit may bring other questions, issues and uncertainty
into consideration. In E1, the SDT developed an alternative response to a directive
which appears to be a very good work-around. Although we don’t have specific
language to offer, could the SDT develop a similar alternative for E3 without totally
eliminating the existing 100 kV limit?
Regarding the 30 kV limit in Note 2 of E1, does incorporating this value in the Note
imply or could it be interpreted that these particular 30-100 kV looping facilities
would become part of the BES? Although they aren’t specifically addressed in any of
the Inclusions, perhaps it would be appropriate to specifically state that they would
not be included.
If an entity had two 115 kV radial lines and adds a looping 34.5 kV line between them
that is operated normally closed, are these facilities considered radial lines subject to
E1 or Local Networks subject to E3?
Response: Although Note 2 is directly linked to Exclusion E1 in the definition, the threshold value is a direct reflection of what
constitutes a local network. The presence of sub-100 kV loops below the threshold value, for example, a <30 kV loop, does not affect
the ability to apply the criteria of Exclusion E1 to the subject facilities. However for loops that operate at a voltage of >30 kV, the
subject facilities are required to be evaluated based on the criteria of Exclusion E3 (local networks). Therefore, no clarification is
necessary in regards to the language in Exclusion E3.
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The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the
Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the
bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A,
paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not
be included in the bulk electric system, unless determined otherwise in the exception process.”
Based on the proposed threshold value of 30 kV for looped facilities, in the example provided, the configuration would not be subject
to the criteria of Exclusion E1 (radial system) and would require evaluation under the criteria of Exclusion E3 (local network).
Seminole Electric
Yes
Exclusion E1 allows for the exclusion of radials that contain particular amounts of
load and generation resources; however, there is no mention of radials that contain
reactive devices. Therefore, if a radial falls under Exclusion E1(c) for generation and
load, but also has a reactive device, it is unclear whether this Exclusion can be
utilized. From past discussions, it appears that E1(c) covers reactive devices;
however, Seminole asks that the SDT revise/clarify this Exclusion to specifically
include reactive devices.
Response: Exclusion E1 establishes criterion that is based on the presence of Load and generation. Reactive devices are not a
determinative factor when assessing a potential radial system for exclusion from the BES. Exclusion E1 does not address reactive
devices. Reactive devices are subject to the criteria established by Inclusion I5 and Exclusion E4. No change to Exclusion E1 was
made.
US Bureau of Reclamation
Yes
First, Reclamation suggests that the term “normally open” in E1 Note 1 is vague and
should include some type of threshold for what is “normally open” (e.g. 80% of
annual operating hours). The Bureau interprets "normally open" to mean under
normal conditions rather than under emergency or maintenance conditions.
Reclamation believes clarification of the term is necessary to make compliance
obligations clear and avoid a variety of regional and entity interpretations about
which switches qualify as “normally open.”
Second, Reclamation believes that certain aspects of Inclusion I2 are quite
problematic. Inclusion I2 implies that a generation step-up transformer (GSU) is
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considered part of the generator in the BES designation by stating that "[g]enerating
resource(s) ... including the generator terminals through the high-side of the step uptransformer(s) connected at a voltage of 100 kV or above..." are considered BES.
However, this does not address situations where there is more than one transformer
before the transmission voltage. For example, a qualifying generator may pass
through multiple series transformers, of which only the last has terminals at 100kv or
above. The first transformer in the series would be considered the generator step
up-transformer but not the other transformers in the series. Such series of
transformers could also involve sections of line which then raises the question of
how they are classified. A generator greater than 20 MW Generator could be
stepped up to some under 100 kV voltage, run some distance to a BES substation
and then be transformed at that station to 100 kV or greater voltage. It seems that
this would be not deemed a Generation Resource under I2 and would avoid needing
to meet any requirements. Finally, in some instances, the Transmission Owner may
own, operate, and maintain GSUs. To address this lack of clarity, Reclamation
suggests that the drafting team revise the BES definition to better address GSUs in a
separate inclusion.
In addition, if GSUs with only one terminal over 100kv are considered BES,
Reclamation questions why other transformers must have a "primary terminal and at
least one secondary terminal operated at 100kv or higher" to be considered BES
resources.
Third, Reclamation suggests that NERC clarify the relationship between the new BES
definition and roles described in the functional model. The Functional Model does
not address roles and responsibilities related to transformers. In some instances, a
Transmission Owner may own GSUs and it is unclear whether the Generator Owner
or Transmission Owner would have compliance responsibility for the GSUs.
Finally, Reclamation suggests that NERC define the term "generation resources" to
clarify which generator components are considered part of "generation resources."
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Response: Note 1 under Exclusion E1 states: “A normally open switching device between radial systems, as depicted on prints or
one-line diagrams for example, does not affect this exclusion.” Based on the development record of Phase 1 of the project, the
industry has not identified any concerns with the clarity of the classification of ‘normally open’. This is a standardized term used in
the operating realm of the industry and does not need further clarification beyond identification of the device as being a ‘normally
open’ on a print or operating one-line diagram.
The step-up transformer(s) associated with generation resources are considered part of the generation resource and included in the
BES by application of Inclusion I2. The BES Reference Document provides specific examples that address this generation resource
concern (See Figures I2-5 and I2-6). In these examples the use of multiple transformers and interconnecting bus work is described
for various scenarios. Figure I2-5 describes a generation resource that utilizes multiple step-up transformers and interconnecting bus
work that is installed for the sole purpose of stepping up the voltage output of the generator to a voltage of 100 kV or above. Based
on this scenario the generation resource is considered to be a BES Element. Figure I2-6 describes a generation resource that utilizes
multiple step-up transformers and interconnecting bus work that serves two purposes: first, the interconnecting bus work serves
off-site Load at a voltage level <100 kV, and second provides a connection of the generation resource to a voltage level > 100 kV.
Based on this scenario the generation resource is not considered to be a BES Element.
Transformers identified in Inclusion I1 serve a Transmission function. Step-up transformers associated with generation resources are
utilized for the purpose of connecting generation to voltages >100 kV. Both classifications of transformers serve a purpose
associated with either Transmission reliability or generation resource reliability. No change made.
The BES definition is a component-based definition that does not take into account the ‘ownership’ of a facility. Ownership
establishes registration and registration establishes the applicability of Reliability Standards. No change made.
Defining the term ‘generating resource’ is beyond the scope the Project 2010-17. Based on the development record of Phase 1 of
the project, the industry has not identified any concerns with the clarity of the term ‘generating resource’. The SDT feels that the
term is well known in the industry and further clarification is not necessary. No change made.
City of Anaheim
Yes
For clarity, a minor grammatical change should be incorporated into Inclusion I2.
Specifically, a comma should be placed after the word “transformer(s)” and before
the phrase “connected at a voltage of 100 kV or above.” Thus, Inclusion I2, as
revised, should state: Inclusion I2 - Generating resource(s) and dispersed power
producing resources, including the generator terminals through the high side of the
step-up transformer(s), connected at a voltage of 100 kV or above with: a) Gross
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individual nameplate rating greater than 20 MVA, orb) Gross plant/facility aggregate
nameplate rating greater than 75 MVA.
Response: The proposed revision would change the intent of Inclusion I2. The language “…connected at a voltage of 100 kV or above
…” refers to the transformer connection voltage not to the generator connection voltage. No change made.
ACES Standards Collaborators
Yes
Given that Facilities below 100 kV could be included in the definition of the BES by
the BES exception process, the drafting team should consider removing “of 100 kV or
higher” from E1. Any radial facility regardless of voltage class should be excluded.
By removing the clause, we think it will offer further support to exclude radial
facilities below 100 kV that a requester may attempt to add via the BES exception
process. We understand the exclusion is intended to apply to the bright line
definition of 100 kV which offers further reason to remove the clause. Because it
can only ever apply to 100 kV or higher facilities, it is superfluous.
Response: The language “of 100 kV or higher” currently contained Exclusion E1 has been retained from the Phase 1 definition that
has been approved by the Commission. Removal of the language does not improve clarity or address issues associated with
implementation, therefore the language will be retained in the Phase 2 definition.
Georgia Transmission
Corporation
Yes
GTC recommends the additional clarifier to E4: Reactive Power devices installed for
the sole benefit of a retail or wholesale customer.
Response: This proposed revision would potentially exclude every Reactive Power device. The Reactive Power devices that are
intended to be excluded by application of Exclusion E4 have specific functionalities/purposes associated with their installations. For
example: Power quality applications designed to meet customer strict criteria for voltage tolerances. No change made.
Arizona Public Service Company
Yes
I5 is still problematic. It only excludes reactive resources which are excluded by E4.
We suggest following: “unless excluded by exclusion of E1 to E4”. For example there
is no justification to include reactive resources connected to a radial system as part
of BES which are there to serve the radial system. Since the radial system is not part
of BES, why include the reactive resources connected to radial system as part of BES.
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Response: The results of the NERC Planning Committee’s (PC) evaluation of the reactive resource threshold contained in the BES
definition were presented to the SDT for consideration in developing revisions to the definition in Phase 2. The PC determined that
all reactive resources regardless of size are material to the reliability of the BES. The SDT is basing the inclusion of reactive resources
on the PC analysis. No change made.
Iberdrola USA
Yes
It seems counter-intuitive that a 600 MVAR dynamic range SVC directly connected to
the 345 kV system would have the 345 kV bus and the 18 kV bus-connected
capacitive & reactive equipment be BES, yet the 345/18 kV transformer would not be
BES.
The NERC “BES Definition Reference Document” is an important aid in interpreting
different circumstances of applicability of the BES Definition. It should be kept up to
date as the definition changes, with specific examples of applications of those
changes. Specific comments on the “Reference Document” are: o For BES Exclusion
E2 (behind-the-meter customer-owned generation), the NERC SDT recommends
using 1 year of integrated hourly revenue metering to test for flow into the BES of
less than 75 MVA. However, for BES Exclusion E3 (local networks), the NERC SDT
recommends using 2 years of integrated hourly metering to test for flow into the BES
at all points of connection of the candidate local network to the BES.
o Several figures seem to have possible exclusions that are not mentioned, in
portions of those figures. Specifically: o Figures E1-4a, E1-5, and E1-6 have the same
15 MVA, then 10 MVA generator on the middle left of the diagram that could have
its generator lead to the tap point qualify for a radial exclusion; but the tapped lead
is shown as BES. The vertical blue line from the 100 kV bus would still be BES.
o Figures E1-7a, E1-8a, E1-9, and E1-10 have either radial loads or industrial
customers with retail generation on the middle left and right of the diagram that
could have their tapped supply lines qualify for a radial exclusion; but the tapped
lines are shown as BES. The vertical blue line from the 100 kV bus would still be BES.
o Figure S1-9b only considers the 69 kV network as a candidate for a local network
exclusion. This is not a valid consideration, because whether or not the red arrows
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point up or down, the 69 kV system is not BES by nature of the core definition.
Moreover, there are not enough points measured to determine flow polarity of the
parallel parts of the 138 kV system. It would be necessary to either/also measure 2
other points on the 138 kV network for that network to be a candidate for the local
network exclusion. No conclusions or recommendations can be drawn from this
example as shown.
Figures S1-10, S1-11, and S1-12 show the entire 138 kV loop on the left of the
diagram as a local network exclusion (shown as green) - as noted above this is not
consistent with FERC Order 773 and 773-A, nor Figures S1-9a and S1-9b.
Response: The SDT determined that the BES is not required to be contiguous in nature. The SDT has addressed the concerns raised
by the Commission in Orders 773 & 773A on the topic of contiguity.
The SDT appreciates the comments concerning the BES Definition Reference Document; however this comment period concerns the
Phase 2 revision of the BES definition. As the SDT gains more certainty in final outcome of the definition development the BES
Definition Reference Document will be updated and posted for industry comment.
New York State Department of
Public Service
Yes
NERC has an obligation to provide technical advice to FERC, so that any number
provided to FERC by NERC is interpreted as technical advice. A major purpose of the
BES Phase II effort was to establish a technical basis for the 100 kV brightline and the
20/75 MVA generation levels. While NERC has provided a report purportedly
providing a technical basis for these threshold levels, the report fails to do so. NERC
should not include any numbers in any definition or standard for which it cannot
provide a technical basis. Surveys do not provide a technical basis. Particularly
troublesome is the presentation of alternatives to the 100 kV brightline. The report
authors looked at 5 alternatives to establishing a technical basis for determining the
bulk system. The report failed to evaluate the methodology historically applied to
the NPCC system. If a major NERC region was able to successfully apply their
methodology, why was it not evaluated and why would it be impossible to expect
other regions to perform a similar analysis as the base for determining the BES?
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Response: The results of the NERC Planning Committee’s (PC) evaluation of the various thresholds contained in the BES definition
were presented to the SDT for consideration in developing revisions to the definition in Phase 2. The PC determined that all
thresholds should remain at the status-quo. The SDT, based on the recommendations from the PC, has opted to retain the original
thresholds in the definition.
Self
Yes
NERC is an international body. The BES SDT in any next version of the Phase 2
definition should take full account of Canadian regulatory frameworks. NERC must
consider all jurisdictions. The existing legislated definitions of "distribution" in the
Provinces must be allowed for in any definition of BES even if it is though a "local
jurisdiction" exception footnote.
Response: Jurisdictional concerns between regulatory authorities are beyond the scope of this project and are not the responsibility
of the SDT to resolve. The proper channels exist to address these concerns; however they reside outside of the Standard
Development Process.
Tri-State Generation and
Transmission, Inc.
Yes
Notwithstanding the NERC “Review of Bulk Electrical System Definition Thresholds”
published in March, 2013, Tri-State continues to believe that there is no reliability
benefit to the BES by having no minimum threshold for reactive devices on radial or
non-radial systems. Two items in particular give cause for concern about the
recommended resolution in the review. First, the review states that, since there is no
clear technical justification for the threshold on generator size, any basis for setting a
threshold for reactive devices comparable to the BES definition for generators does
not have a technical basis. That is in itself a circular, non-technical response, and not
a technical reason for not having a threshold for the reactive devices. The other
argument that only 5% of the reactive devices would be excluded by using a
threshold also has no technical merit. Secondly, the review did not even attempt to
analyze what step voltage change a reactive device might have when it is in service.
There are multitudes of reasons why a reactive device might be placed at a location
and its unavailability may have a very small impact on the reliability of a system.
Certainly it could have much less impact on system, especially a radial system, than
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loss of a 20 MW generator or a 75 MW aggregate plant would have.
In addition, Tri-State believes that reactive devices installed on radial systems are
equivalent to reactive devices installed for the sole benefit of retail customers (E4)
and exclusion E1 should be added to the end of I5, i. e. “... excluded by application of
E1 or E4.”
Tri-State also disagrees with the findings in the same review regarding exclusions of
Local Networks. Once again, the alleged lack of a technical basis for BES generator
size is used as rationale for not allowing any flow out of a Local Network in Technical
Alternative A. There is no technical merit to that argument.
The argument for disregarding Technical Alternative B also seems to have no
technical basis. Tri-State continues to believe that Local Networks could be excluded
based on a minimum percentage of time that real/reactive power may flow out of
the network. An unintended consequence of not allowing this to occur may be that
entities will begin operating these systems radially to avoid falling under the
definition of the BES.
Response: Phase 2 of the project included an evaluation of the thresholds contained in the BES definition. This task was assigned to
the NERC Planning Committee (PC). The results of the NERC PC’s evaluation were presented to the SDT for consideration in
developing revisions to the definition in Phase 2. The content and conclusions drawn by the NERC PC are beyond the control of the
SDT.
Exclusion E1 establishes criterion that is based on the presence of Load and generation. Reactive devices are not a determinative
factor when assessing a potential radial system for exclusion from the BES. Exclusion E1 does not address reactive devices. Reactive
devices are subject to the criteria established by Inclusion I5 and Exclusion E4. No change to Exclusion E1 was made.
New York Power Authority
Yes
Phase 2 of the BES definition process was supposed to address the 100kV threshold,
the generator thresholds and the reactive resource thresholds for inclusion or
exclusion. No formal studies have shown that these numbers are the correct
numbers for this definition. The studies provided under phase 2 had no more
technical justification than those discussions by the SDT under phase 1. Being able
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to have that technical justification provides the support necessary to maintain a
reliable transmission system and provides a basis for analysis of reliability by industry
participants.
Response: Phase 2 of the project included an evaluation of the thresholds contained in the BES definition. This task was assigned to
the NERC Planning Committee (PC). The results of the NERC PC’s evaluation were presented to the SDT for consideration in
developing revisions to the definition in Phase 2. The content and conclusions drawn by the NERC PC are beyond the control of the
SDT.
American Transmission Company Yes
Please clarify that E3b is to be applied for normal (intact) and emergency system
conditions. Rewording suggestion is as follows: E3b) Power flows only into the LN
under normal and emergency conditions and the LN does not transfer energy
originating outside the LN for delivery through the LN;
Also ATC believes the SDT should include a note to define normal and emergency
conditions.
Response: The BES definition is stateless (i.e., normal, emergency, or restorative). No change made.
Defining terms such as normal and emergency conditions is beyond the scope of the approved SAR for this project. No change made.
Southern California Edison
Yes
SCE requests that NERC properly define “non-retail generation.” SCE’s
understanding of the term “non-retail generation” is to describe those generation
facilities whose purpose is to exclusively sell power into wholesale markets. This
understanding would define Co-Generation facilities as “non-retail,” and therefore
not counted in the 75 MVA aggregate threshold amount. In addition, the 75 MVA
aggregate thresholds defined by the gross nameplate MVA rating of the generators
would count generating facilities where the generators individually and/or in
aggregate meet the 75 MVA threshold but exports less than 75 MVA to the grid. The
clarification of “non-retail” generation is important since summing-up generators
producing this power is a major factor for determining what “wires and lines” meet/
don’t meet the E1 and E2 Exclusions.
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Response: The SDT provided the following clarification concerning non-retail and retail generation in the BES Definition Reference
Document. Non‐retail generation is any generation that is not behind a retail customer’s meter. Retail generation is behind the
meter generation with all or some of the generation serving the on-site Load. Based on the description provided for ‘co-generation’
facilities, it appears that based on the statement concerning ‘exports to the grid’; co-generation facilities are considered to be ‘retail’
generation and therefore are not included in the aggregate totals for evaluation of radial systems (Exclusion E1) or local networks
(Exclusion E3). No change made.
Sacramento Municipal Utility
District
Yes
SMUD remains concerned regarding the limits imposed on local networks. We note
that by order 773A, FERC considers this limit to be absolute with no allowance for
minimal reverse flows for even brief periods under multiple contingencies. While
denying rehearing on this issue, FERC specifically invited Phase 2 to adjust this
outcome in paragraph 79 of the order. We also note that the BES Definition
Reference would allow very brief flows out of a local network as long as the
integrated hourly flow was still into the local network. FERC, however, did not rule
on the Reference document, only the definition itself. Even if FERC did allow the
language of the Reference document, the first multiple contingency event that
results in out flow or through flow for the better part of an hour would cause an
excluded network to become immediately included, and subject to standards
without any implementation period (assuming 24 months had passed from the
effective date of the definition). The Planning Committee provided several options
to SDT on this matter. We understand the SDT’s reluctance to impose system studies
on what is intended to be a simply determined bright line criterion, but the present
exclusion is not very useful. SMUD supports including the option of perform one
element out (“N-1”) contingency at peak conditions or a fixed two year (or longer)
window could be used rather than the most recent two year sliding window
suggested in the reference document. These options would provide more certainty
and better support the reliability of the BES. However it is determined, it should be
included within the approved definition so that the reference document disclaimer
does not apply.
Non-retail generation still lacks a definition to be approved by NERC and FERC, even
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though this this item was specifically included in the approved SAR. We note that the
term is defined in the Reference Document where the disclaimer stating it is not an
official position of NERC makes this definition of little value. While the Reference
Document states “Non-retail generation is any generation that is NOT behind a retail
customer’s meter,” we continue to hear it defined without the “not.” It is very
important that entities and regions have a common understanding of the term, and
ask the team to include its definition within the BES definition.
Public Utility District No.1 of
Snohomish County
Yes
The Public Utility District No.1 of Snohomish County remains concerned regarding
the limits imposed on local networks. We note that by order 773A, FERC considers
this limit to be absolute with no allowance for minimal reverse flows for even brief
periods under multiple contingencies. While denying rehearing on this issue, FERC
specifically invited Phase 2 to adjust this outcome in paragraph 79 of the order. We
also note that the BES Definition Reference would allow very brief flows out of a
local network as long as the integrated hourly flow was still into the local network.
FERC, however, did not rule on the Reference document, only the definition itself.
Even if FERC did allow the language of the Reference document, the first multiple
contingency event that results in out flow or through flow for the better part of an
hour would cause an excluded network to become immediately included, and
subject to standards without any implementation period (assuming 24 months had
passed from the effective date of the definition). The Planning Committee provided
several options to SDT on this matter. We understand the SDT’s reluctance to
impose system studies on what is intended to be a simply determined bright line
criterion, but the present exclusion is not very useful. The Public Utility District No.1
of Snohomish County supports including the option of perform one element out (“N1”) contingency at peak conditions or a fixed two year (or longer) window could be
used rather than the most recent two year sliding window suggested in the
reference document. These options would provide more certainty and better
support the reliability of the BES. However it is determined, it should be included
within the approved definition so that the reference document disclaimer does not
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apply.
Non-retail generation still lacks a definition to be approved by NERC and FERC, even
though this item was specifically included in the approved SAR. We note that the
term is defined in the Reference Document where the disclaimer stating it is not an
official position of NERC makes this definition of little value. While the Reference
Document states “Nonâ€retail generation is any generation that is not behind a
retail customer’s meter,” we continue to hear it defined without the “not.” It is very
important that entities and regions have a common understanding of the term, and
ask the team to include its definition within the BES definition.
Response: Exclusion E3b defines an absolute value associated with power flow from a local network to maintain the bright-line
concepts of the definition. The SDT has determined that the best method to quantify the amount of power flow associated with a
local network is to evaluate the hourly integrated flows over the most recent 2 year period. Although this allows for some amount of
flow from the local network this is considered to be inconsequential when considering the impact of minimal flows over very short
periods of time. The 2 year period is recommended as a sliding time frame to account for system changes that periodically occur on
any electrical system. For instances that result in a change of BES classification of a subject local network, the entity should contact
it’s Regional Entity for the Regional practices that address the situation in question. The disclaimer in the BES Definition Reference
Document is under the purview of NERC Legal and is not under the control of the SDT. No change made.
The Phase 2 SAR identified the following in regards to clarification associated with non-retail generation.
Provide improved clarity to the following: The use of the term “non-retail generation”
The SDT provided the following clarification concerning non-retail and retail generation in the BES Definition Reference Document.
Non‐retail generation is any generation that is not behind a retail customer’s meter. Retail generation is behind the meter
generation with all or some of the generation serving the on-site Load. No change made.
Transmission Access Policy Study
Group
Yes
TAPS applauds the SDT’s work to address FERC’s directives on a very accelerated
timeline, as well as the SDT’s hard work on this project over the last six years.
Response: Thank you for your support.
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Southern Company: Southern
Company Services, Inc.; Alabama
Power Company; Georgia Power
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
Yes
Question 6 Comment
The 2010-17 project webpage indicates that the Planning Committee’s March 2013
report addresses the technical justification of threshold values, and that it will be
updated by the drafting team after the definition has been revised in Phase 2.
In its comments submitted in Project 2010-17 on February 2, 2012 (“Initial Comment
Form”), Southern responded to two questions posed by the SDT that asked about
the propriety of pursuing technical justification, but did not appear to be directly
related to the threshold values. Southern includes those responses here for the
SDT’s convenience. First, in Question 3 of the Initial Comment Form, the SDT asked
whether it should pursue justification that supports the assumption that there is a
reliability benefit of a contiguous BES. In Order 773, FERC stated that “it is generally
appropriate to have the BES contiguous.” (P 167). To the extent that “contiguous”
may be considered synonymous with “interconnected”, Southern agrees that
pursuing technical justification to support such an assumption may be appropriate.
Second, in Question 5 of the Initial Comment Form, the SDT asked whether it should
pursue technical justification to support including an automatic interrupting device
in Exclusions E1 and E3. It is not entirely clear whether this was addressed by FERC in
either Order 773 or Order 773-A. As Southern stated in its February 12, 2012
comments, the scope of the term “automatic interrupting device” is unclear and
could benefit from some clarification by NERC. To the extent that the term
“automatic interrupting device” would constitute gas-operated breakers, as opposed
to relays, Southern would agree that such devices, to the extent they are associated
with Radial Systems qualifying under Exclusion E1 and Local Networks qualifying
under Exclusion E3, should also be excluded from the BES under those exceptions.
Response: The Project page for 2010-17 indicates that the ‘technical reference document’ will be updated by the SDT after the
definition has been revised in Phase 2. This reference is to the BES Definition Reference Document and is not related to the NERC
Planning Committee report.
The Phase 2 SAR states the following in regards to the continuity of the BES:
“The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous BES - Determine if
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there is a need to change this position.”
In Orders 773 and 773A the Commission provided directives that speak directly to the issue of continuity of the BES. The SDT has
addressed the Commission’s concerns in regards to embedded BES generation that resides in a radial system or local network. As
stated in the comment the Commission feels that it is generally appropriate to have a contiguous BES. Based on the Commission’s
documented directives the SDT has revised the BES definition accordingly.
The Phase 2 SAR posting yielded comments that eliminated automatic interrupting devices (AID) from the scope of the SAR.
Ameren
Yes
The determination of BES facilities should be straight-forward and easy for both
entities and auditors to review and understand. We agree that, implementation of
some bright-line criteria to determine BES facilities are in the best interest of
reliability. We encourage the SDT to streamline the 78 page BES guidance document
because we feel the process of determining BES facilities is still not straight-forward.
Response: The purpose of the BES Definition Reference Document is to assist the industry with the application of the revised
definition. The document is intended to provide clarification and explanations for the application of the revised definition in a
consistent, continent‐wide basis for the majority of BES Elements. The recommended application of the definition is contained in the
‘hierarchical application’ (Section IV) and provides a step-by-step process for the determination of BES and non-BES Elements.
Sections II & III provide examples of the application of the various Inclusions and Exclusions contained in the definition. Although it
appears that the number of examples is excessive, the diversity of components comprising the interconnected Transmission network
dictates the need to be as detailed as possible to cover the vast majority of situations. With that being said the examples that are
provided should not be considered as all inclusive and when industry requests additional clarification that can be provided through
additional diagrams the SDT will make every effort to accommodate the request.
Public Service Enterprise Group
Yes
The issue of requiring facilities that connect BES generation to the grid to be included
in the BES was settled by FERC in Order 773. We believe that consistency is needed
on the issue of contiguity; furthermore, this was a Phase 2 issue that SDT is supposed
to address per its SAR - see page 2 of the SAR which states a portion of the scopes as
follows: “The NERC Board of Trustees approved BES Phase 1 definition does not
encompass a contiguous BES - Determine if there is a need to change this position.”
For example, the connection of reactive devices to the grid in the Guidance
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document (pp. 21-22) are in “black” that “indicates Elements that are not evaluated
for the specific inclusion depicted in the individual diagrams being shown.” The SDT
should complete the activities in its SAR in Phase 2 or explain why it has not.
Response: The Phase 2 SAR states the following in regards to the continuity of the BES:
“The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous BES - Determine if
there is a need to change this position.”
In Orders 773 and 773A the Commission provided directives that speak directly to the issue of continuity of the BES. The SDT has
addressed the Commission’s concerns in regards to embedded BES generation that resides in a radial system or local network. As
stated in the comment the Commission feels that it is generally appropriate to have a contiguous BES. Based on the Commission’s
documented directives the SDT has revised the BES definition accordingly.
North American Generator
Forum Standards Review Team
Yes
The language of the proposed BES definition is rather convoluted and is therefore
difficult to apply correctly without the Guidance Document. The FERC order
773/773a-amended Guidance Document is not complete or final for the phase-2 BES
definition, however. Its exclusion E1 statement is that of phase-1, not phase-2, for
example, and a disclaimer on p.1 states that “...this reference document is outdated.
Revisions to the document will be developed at a later date to conform to the
definition being developed in Phase 2.” It appears that the phase-2 BES definition is
being rushed through the approval process, and it would be preferable to take the
time to compile a complete and consistent body of documentation before putting
the matter up for a vote.
PPL NERC Registered Affiliates
Yes
The language of the proposed BES definition is rather convoluted and is therefore
difficult to apply correctly without the Guidance Document. The FERC order
773/773a-amended Guidance Document is not complete or final for the Phase-2 BES
definition. Its exclusion E1 statement is that of phase-1, not Phase-2, for example,
and a disclaimer on p.1 states that “...this reference document is outdated.
Revisions to the document will be developed at a later date to conform to the
definition being developed in Phase 2.” It appears that the Phase-2 BES definition is
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being rushed through the approval process, and it would be preferable to take the
time to compile a complete and
Response: The SDT appreciates the comments concerning the BES Definition Reference Document; however this comment period
concerns the Phase 2 revision of the BES definition. As the SDT gains more certainty in final outcome of the definition development
the BES Definition Reference Document will be updated and posted for industry comment. Phase 2 of the project is being conducted
in accordance with the Standards Process Manual and the project schedule has been developed to support the implementation of
the Phase 2 definition on July 1, 2014.
Hydro-Quebec TransEnergie
Yes
The main concern about phase 2 definition is that it reduces more than phase 1
definition the possibility of exclusions, and that no proper technical analysis had
been given to justify or reduce the proposed threshold. FERC's request should not
force obligations on non-US jurisdiction, but non-US jurisdiction should be consulted
equally by NERC.
Response: It is not clear from the comments what specific concerns should be considered for potential revision. The SDT recognizes
that in being responsive to the Commission directives the scope of the BES has incrementally increased, however the ERO is
obligated to address the Commission’s concerns and the SDT has determined that the revisions in the proposed definition
adequately address these concerns.
Jurisdictional concerns between regulatory authorities are beyond the scope of this project and are not the responsibility of the SDT
to resolve. The proper channels exist to address these concerns; however they reside outside of the Standard Development Process.
Delta-Montrose Electric
Association
Yes
The proposed BES definitions need more clarification, and the utilities should be
granted more time for comments and responses.
Response: Phase 2 of the project is being conducted in accordance with the Standards Process Manual and the project schedule has
been developed to support the implementation of the Phase 2 definition on July 1, 2014.
Northeast Power Coordinating
Council
Yes
The specifics of system configurations and applications in the Inclusions and
Exclusions should be reviewed to be made less complex. If they are not simplified
they can be expected to generate a large number of requests for exclusion
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consuming resources in regional processing and at the ERO. As an alternative, an
updated, conforming Guidance Document clarifying the intent and containing
explicit explanations and one-line diagram examples should be provided. The version
previously posted does not conform to the Phase 2 changes proposed.
Phase 2 of the BES definition process was supposed to address the 100kV threshold,
the generator thresholds and the reactive resource thresholds for inclusion or
exclusion. No formal studies have shown that these numbers are the correct
numbers for this definition. The studies provided under Phase 2 had no more
technical justification than those discussions by the Standard Drafting Team in Phase
1. Being able to have that technical justification provides the support necessary to
maintain a reliable transmission system and provides a basis for analysis of reliability
by industry participants.
Based on FERC orders 773 and 773-A and NERC’s response to those orders, the value
of Note 1 under E1 has been diminished and suggest it be removed. It must be
considered that industry has typically considered the terms ‘network’ and
‘contiguous’ to exclude elements or facilities that contain a normally open device
(switch, breaker, disconnect, etc.) between them.
1) NERC must consider that any new or changes to standards as a result of FERC
directives that apply to load reliability and load supply continuity are limited to the
FERC jurisdiction only. For example, in Canada, local load reliability requirements are
under the authority of local regulators such as the OEB in Ontario.
2) The Implementation Plan does not conflict with the Ontario regulatory practice
with respect to the effective date of the standard. It is suggested that this conflict be
removed by appending to the effective date wording, after “applicable regulatory
approval” in the Effective Dates Section of the Implementation Plan, the following:”,
or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.” The same changes should be made to the first sentence
in the Effective Date Section on page 2 of the Definition document.
Consideration of Comments: Project 2010-17 | August 2, 2013
140
Organization
Yes or No
Question 6 Comment
The main concern about the Phase 2 definition is that it reduces more than the
Phase 1 definition by the possibility of exclusions, and that no proper technical
analysis had been given to justify or reduce the proposed threshold. FERC's request
should not force obligations on non-United States jurisdictions. NERC must consult
with and treat both United States and non-United States jurisdictions equally.
Response: The purpose of the BES Definition Reference Document is to assist the industry with the application of the revised
definition. The document is intended to provide clarification and explanations for the application of the revised definition in a
consistent, continent‐wide basis for the majority of BES Elements. The recommended application of the definition is contained in the
‘hierarchical application’ (Section IV) and provides a step –by-step process for the determination of BES and non-BES Elements.
Sections II & III provide examples of the application of the various Inclusions and Exclusions contained in the definition. Although it
appears that the number of examples is excessive, the diversity of components comprising the interconnected Transmission network
dictates the need to be as detailed as possible to cover the vast majority of situations. With that being said the examples that are
provided should not be considered as all inclusive and when industry requests additional clarification that can be provided through
additional diagrams the SDT will make every effort to accommodate the request.
Phase 2 of the project included an evaluation of the thresholds contained in the BES definition. This task was assigned to the NERC
Planning Committee (PC). The results of the NERC PC’s evaluation were presented to the SDT for consideration in developing
revisions to the definition in Phase 2. The content and conclusions drawn by the NERC PC are beyond the control of the SDT.
The SDT feels that Note 1 under Exclusion E1 provides necessary clarity to the exclusion and has determined that the note will be
retained.
After conferring with NERC Legal, the SDT has revised the jurisdictional language.
This definition shall become effective on the first day of the second calendar quarter after applicable regulatory approval. In
those jurisdictions where no regulatory approval is required the definition shall go into effectbecome effective on the first
day of the second calendar quarter after Board of Trustees adoption or as otherwise made effective pursuant to the laws of
applicable governmental authorities.
The SDT recognizes that in being responsive to the Commission directives the scope of the BES has incrementally increased, however
the ERO is obligated to address the Commission’s concerns and the SDT has determined that the revisions in the proposed definition
adequately address these concerns.
Consideration of Comments: Project 2010-17 | August 2, 2013
141
Organization
Yes or No
Pepco Holdings Inc & Affiliates
Yes
Question 6 Comment
There were many suggestions and comments on the first draft of the BES Reference
Document. As the SDT continues to revise the document, it is hoped that the SDT
consider including additional figures to provide for clarification. It is recognized that
there are probably many individual, unique configurations and that every one of
them cannot or should not be included. However, consideration should be given to
general clarifications that will aid the entire industry in understanding the details of
the definitions application.
Response: Thank you for your comments.
City of Tacoma
Yes
TPWR remains concerned regarding the limits imposed by b) on local networks. We
note that by order 773A, FERC considers this limit to be absolute with no allowance
for minimal reverse flows for even brief periods under multiple contingencies. While
denying rehearing on this issue, FERC specifically invited Phase 2 to adjust this
outcome in paragraph 79 of the order. We also note that the BES Definition
Reference would allow very brief flows out of a local network as long as the
integrated hourly flow was still into the local network.
There is no phase in period for a facility that loses its BES exclusion. For example,
should a local network experience multiple contingencies that causes an unusual
power flow disqualifying its exclusion, then 24 months should be allowed to resume
BES applicability.
Response: Although Exclusion E3b defines an absolute value associated with power flow from a local network to maintain the
bright-line concepts of the definition. The SDT has determined that the best method to quantify the amount of power flow
associated with a local network is to evaluate the hourly integrated flows over the most recent 2 year period. Although this allows
for some amount of flow from the local network this is considered to be inconsequential when considering the impact of minimal
flows over very short periods of time. For instances that result in a change of BES classification of a subject local network, the entity
should contact it’s Regional Entity for the Regional practices that address the situation in question.
American Electric Power
Yes
Under E3, did the team intend to also eliminate the 100kv threshold from the phrase
Consideration of Comments: Project 2010-17 | August 2, 2013
142
Organization
Yes or No
Question 6 Comment
“LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service...”?
Response: No, the SDT retained the phrase to maintain the clarity associated with the identification of the multiple points of
connection.
ITC
Yes
Via the information disseminated by the SDT, it appears to us that the drafting team
intended the additions to E1 to essentially say that loops between radial systems at
voltages over 30 kV are BES and cannot be excluded through the application of E3b.
This is an attempt at establishing as much of a bright line as possible and is
embodied in Note 2 under E1. We are having trouble seeing this in the proposed
standard language. Regardless, to meet this intent the language in E1 needs to be
cleaned up and E3b removed. Alternatively, another Inclusion could be added to
cover the above 30 kV networked facilities to meet this intent.
Further, we don’t agree with establishing a 30 kV bright line for parallel systems, as
we envision this being fought in the courts as an encroachment into distribution, and
will get bogged down. Rather, something that can be reasonably expected to be
adopted now should be proposed so that we can get clarity/alignment with the
phase 1 effort and then come back for a phase 3 effort to determine the best
process for dealing the sub-100 kV networks.
The reference to 30 kV should be removed altogether and the PC recommendations
for E3b should be adopted (The PC recommendation follows):(Begin PC quote)
""Real power flows only in the LN from every point of connection to the BES for the
system as planned with all lines in service and also for first contingency conditions as
per TPL-001-2, Steady State & Stability Performance Planning Events P0, P1, and P2,
and the LN does not transfer energy originating outside the LN for delivery through
the LN to the BES."""""" (end of PC quote)Note that the first contingency conditions
referred to above must include contingencies of elements within the proposed Local
Network in addition to contingencies on the proposed BES. This should be explicitly
stated in the standard so there’s no confusion.
Consideration of Comments: Project 2010-17 | August 2, 2013
143
Organization
Yes or No
Question 6 Comment
Finally, TPL-001 indicates that it is the Planning Coordinator and the Transmission
Planner responsibilities to perform the studies. For the purposes of application of
the proposed exclusion E3b we recommend that one functional entity be responsible
for this determination (probably the Planning Coordinator).
Response: The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states:
“Thus, the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in
figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission
in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local
networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
The proposed threshold value of 30 kV for looped facilities, is a qualifier for how the 100 kV and above facilities will be evaluated for
potential exclusion, e.g., whether the criteria of Exclusion E1 (radial system) would be used for evaluation or if the looped facilities
exceed the threshold value thus requiring evaluation under the criteria of Exclusion E3 (local network).
The BES definition is a bright-line component based definition. Due to the diverse nature of the interconnected Transmission
network, Introducing study requirements into the bright-line will result in inconsistent results when applied on a continent-wide
basis. The SDT believes that evaluation of facilities by performing studies is best suited for the Exception Process and not the
application of the definition. No change made.
Cooper Compliance Corp
Yes
We recommend that the drafting team address what qualifies as a generator
Interconnection Facility (Transmission Interface) for those radial lines that connect
generation while addressing FERCs concern that generation has to be continuous.
We do not believe that distribution facilities that serve load and that also have
generation connected to it at 100 kV or above should automatically qualify as
Transmission. We recommend that those facilities are Transmission Interface
facilities and instead should be treated in the same manner as a Generator
Interconnection Facility. We ask that the drafting team include within the definition
of Bulk Electric System, the sub BES system otherwise known as the Transmission
Interface. We propose the following definition of Transmission Interface: A
Transmission Interface are the transmission line continuous from the generation
identified in Inclusion I2 and I3 and the static or dynamic devices identified in I5 that
Consideration of Comments: Project 2010-17 | August 2, 2013
144
Organization
Yes or No
Question 6 Comment
absent the generation, static, or dynamic devices would be excluded under E1.
Response: Defining the term ‘Transmission interface’ is beyond the scope the Project 2010-17. The SDT recommends that the
commenter complete and submit a Standard Authorization Request (SAR) identifying the concerns raised here and the proposal to
initiate a project to address the concerns.
Hydro One Networks Inc.
Yes
We suggest NERC must ensure that:1) any new or changes to standards as a result of
FERC directives that apply to load supply reliability and/or continuity be limited to
the FERC jurisdiction only. In Canada, local load reliability requirements are under
the authority of local regulators such as the Ontario Energy Board in the Province of
Ontario.
2) An Implementation Plan does not conflict with Ontario regulatory practice with
respect to the effective date of the standards. It is suggested that this conflict be
removed by appending to the effective date wording, after “applicable regulatory
approval” in the Effective Dates Section of the Implementation Plan, to the following
effect:”, or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.” Prior to the wording “In those jurisdiction....”.The same
changes should be made to the first sentence in the Effective Date Section of the
proposed Definition document.
3) In our opinion, SDT has correctly crafted the language in E1 and E3 in the
approved definition. However it seems that the BES exception process has not been
adequately communicated for “inclusion of facilities” that are not captured by the
definition but may be necessary for the BES operation. To address such FERC
concerns, NERC should take steps (e.g. directing Regions) to provide assurance to
FERC that the exception process will be administered in an effective way by NERC,
Regions and the Reliability Coordinators along with Facility Owners to include sub
100 kV system(s) that are a) used for bulk power transfer (not a sink) across the BES
from one area to the other or b) are necessary for the operation of interconnected
BES in a reliable manner or c) can have an adverse impact on the interconnect BES.
Consideration of Comments: Project 2010-17 | August 2, 2013
145
Organization
Yes or No
Question 6 Comment
Response: 1. Jurisdictional concerns between regulatory authorities are beyond the scope of this project and are not the
responsibility of the SDT to resolve. The proper channels exist to address these concerns; however they reside outside of the
Standard Development Process.
2. After conferring with NERC Legal, the SDT has revised the jurisdictional language.
This definition shall become effective on the first day of the second calendar quarter after applicable regulatory approval. In
those jurisdictions where no regulatory approval is required the definition shall go into effectbecome effective on the first
day of the second calendar quarter after Board of Trustees adoption or as otherwise made effective pursuant to the laws of
applicable governmental authorities.
3. Any assurances made to FERC concerning the BES Exception Process contained in the NERC Rules of Procedure are beyond the
responsibilities of the SDT.
Texas Reliability Entity
Yes
We would like to see a revised Reference Document (and any white papers) posted
prior to the ballot so we can fully understand how NERC intends to implement the
revised definition before voting. There were some surprises in the Reference
Document after Phase 1 was approved by NERC. A revised Reference Document
should be part of the ballot package so that all Ballot Pool members can understand
exactly what they are voting for (and so the NERC Board can understand what it is
approving).
Response: The SDT appreciates the comments concerning the BES Definition Reference Document; however this comment period
concerns the Phase 2 revision of the BES definition. As the SDT gains more certainty in final outcome of the definition development
the BES Definition Reference Document will be updated and posted for industry comment.
Northeast Utilities
Yes
While it is recognized that electrical systems operated below 100KV can be
configured such that they should require BES treatment (i.e. the 92 KV networked
system involved in the 2011 Southern California - Arizona outage), a 30KV threshold
is too low to significantly impact the reliable operation of the higher voltage
transmission system. We propose increasing this threshold to a voltage in the 4050KV range.
Consideration of Comments: Project 2010-17 | August 2, 2013
146
Organization
Yes or No
Question 6 Comment
The new Note 2 associated with Exclusion E1 and the changes to E3 have added
ambiguity that did not exist before. The base definition does not address sub-100kV
contiguous loops. The existing Inclusions do not include sub 100kV contiguous loops
either. Note 2 clarifies that as long as the contiguous loop is below 30kV E1 still
applies. E3 explains how any sub 30kV contiguous loop could be excluded as a local
area network, but there is nothing in the definition to clearly state that contiguous
loops operated below 100kV are considered part of the BES unless excluded by E3.
An additional Inclusion should be added that specifically includes “all contiguous
loop operated below 100kV that is not solely used for the distribute power to load
unless excluded by application of Exclusion E1 or E3.”
The proposed change to the E1 exclusion definition to add Note 2 will require an
examination of NU sub-transmission system connections (69KV in CT and 34KV in
NH) and their connections to the >100KV transmission systems. Elements >100KV
originally categorized as E1 or E3 may become BES inclusions if there is underlying
sub-transmission path. A cursory review determine no elements categorized as E1 in
CT would be changed; however, 16 of the 30 E1 elements in NH could become BES
due to 34KV paths.
Response: The 30 kV value was initially chosen based on a high-level evaluation and was inserted in the definition to introduce the
concept to the industry and seek feedback and technical opinions from the industry. Comments and suggestions were received
questioning the threshold of 30 kV proposed in Note 2 for Exclusion E1. To address this issue, the SDT has created a white paper
that is posted as a supporting document for the second posting of this project which provides a review of regional criteria and
contingency load flow analysis and has determined that 50 kV is the technically justifiable voltage threshold and has changed the
value in Note 2 to 50 kV. This value represents a nominal voltage level (50 kV) that is between operating voltage levels (46 kV and 55
kV) to einsure that a clear bright-line is established.
The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the
Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the
bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A,
paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local networks will not
Consideration of Comments: Project 2010-17 | August 2, 2013
147
Organization
Yes or No
Question 6 Comment
be included in the bulk electric system, unless determined otherwise in the exception process.”
The proposed threshold value of 30 kV for looped facilities, is a qualifier for how the 100 kV and above facilities will be evaluated for
potential exclusion. For example, whether the criteria of Exclusion E1 (radial system) would be used for evaluation or if the looped
facilities exceed the threshold value thus requiring evaluation under the criteria of Exclusion E3 (local network).
MRO NERC Standards Review
Forum (NSRF)
Yes
With E1 (and E3) the SDT has created and “opt-out” process instead of an “opt-in”
process. Only a small portion of networked facilities less than 100kV has a material
impact on the BES. A better approach would be to utilize the BES process for
exceptions and include those that have material impact to the BES. Needlessly
processing these sub 100kV systems through the burdensome exclusion process is
not effective use of resources.
Please clarify that E1 and E3 are to be applied for normal (intact) system conditions.
Rewording suggestions are: E1 - Radial systems: A group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher “under
normal conditions...” E3 - Local networks (LN): A group of contiguous transmission
Elements operated at less than 300 kV “under normal conditions” that distribute
power to Load rather than transfer bulk power across the interconnected system.
MidAmerican Energy
Yes
With E1 (and E3) the SDT has created and “opt-out” process instead of an “opt-in”
process. Only a small portion of networked facilities less than 100kV have a material
impact on the BES. A better approach would be to utilize the BES process for
exceptions and include those that have material impact to the BES. Needlessly
processing these sub 100kV systems through the burdensome exclusion process is
not an effective use of resources.
Wisconsin Public Service / Upper
Peninsula Power
Yes
With E3 and E1 the SDT has created an “opt-out” process instead of an “opt-in”
process. Only a small portion of networked facilities less than 100kV has a material
impact on the BES. A better approach would be to utilize the BES process for
exceptions and include those that have material impact to the BES. Needlessly
processing these sub 100kV systems through the burdensome exclusion process is
Consideration of Comments: Project 2010-17 | August 2, 2013
148
Organization
Yes or No
Question 6 Comment
not an effective use of resources.
Response: The looping facilities that operate at voltages below 100 kV are NOT included in the BES. Order 773, paragraph 155 states:
“Thus, the Commission, while disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements in
figure 3 in the bulk electric system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission
in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub-100 kV elements comprising radial systems and local
networks will not be included in the bulk electric system, unless determined otherwise in the exception process.”
The proposed threshold value of 30 kV for looped facilities, is a qualifier for how the 100 kV and above facilities will be evaluated for
potential exclusion. For example, whether the criteria of Exclusion E1 (radial system) would be used for evaluation or if the looped
facilities exceed the threshold value thus requiring evaluation under the criteria of Exclusion E3 (local network).
Modesto Irrigation District
1. WECC studies have shown that there are thousands of MWs of wind and PV
generating plants currently on-line, and thousands of MWs under development, in
the WECC system, of 20 MW and less capacity. Ignoring the impacts of these units
on the BES would be a mistake, as recent studies by the WECC MVWG (Modeling and
Validation Work Group) have shown.
2. The revisions have made the definition of the BES so complicated, that the
definition is no longer in a form that can be applied in a straight forward and
reasonable manner. Also, there are no technical justifications provided for some of
the exclusion criteria (e.g, 75 MVA and 300 kV values).
Response: 1. The SDT feels that the revisions made to the definition provide the needed clarity to properly address the generating
resource and dispersed power producing resource concerns identified above.
2. The SDT feels that the proposed revisions have improved clarity of the Phase 1 definition while addressing the directives provided
by the Commission in Orders 773 & 773A. Phase 2 of the project included an evaluation of the thresholds contained in the BES
definition. This task was assigned to the NERC Planning Committee (PC). The results of the NERC PC’s evaluation were presented to
the SDT for consideration in developing revisions to the definition in Phase 2. The content and conclusions drawn by the NERC PC are
beyond the control of the SDT.
Consideration of Comments: Project 2010-17 | August 2, 2013
149
END OF REPORT
Consideration of Comments: Project 2010-17 | August 2, 2013
150
**Diagram from PacifiCorp regarding Q4:
Consideration of Comments: Project 2010-17 | August 2, 2013
151
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
Proposed Action Plan and Description of Current Draft:
This draft is the second comment posting and successive ballot for the Phase 2 revised definition of the
Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
Anticipated Delivery
1. Recirculation ballot
3Q13
2. BOT adoption
4Q13
Draft 2 – August 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 2 – August 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•
•
•
•
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources consisting of:
a) Individual resources that aggregate to a total capacity greater than 75 MVA (gross
nameplate rating), and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells. (to be removed from final draft – will be moved to the
Reference Document)
•
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
•
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
Draft 2 – August 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4 with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
•
•
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
Draft 2 – August 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft 2 – August 2013
Page 5 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
Proposed Action Plan and Description of Current Draft:
This draft is the firstsecond comment posting and initialsuccessive ballot for the Phase 2 revised
definition of the Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
Anticipated Delivery
1. Recirculation ballot
3Q13
2. BOT adoption
4Q13
Draft 12 – MayAugust 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition will
go into effect shall become effective on the first day of the second calendar quarter after Board of
Trustees adoption or as otherwise made effective pursuant to the laws of applicable governmental
authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 12 – MayAugust 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•
•
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) and dispersed power producing resources, including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above with:
a) Gross individual nameplate rating greater than 20 MVA,. ORr,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
Rationale for revising I2 to consolidate I2 and I4: Dispersed
power producing resources are small-scale power generation
technologies using a system designed primarily for aggregating
capacity providing an alternative to, or an enhancement of, the
traditional electric power system. Examples could include but are not
limited to solar, geothermal, energy storage, flywheels, wind, microturbines, and fuel cells.
•
•
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Omitted. dDispersed power producing resources consisting of:
a) Individual resources withthat aggregate to a total capacity greater than 75 MVA (gross
nameplate rating), and
b) The utilizing a system designed primarily for aggregatingdelivering capacity from the
point where those resources aggregate to greater than 75 MVA , connected atto a
common point of connection at a voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells. (to be removed from final draft – will be moved to the
Reference Document)
Draft 12 – MayAugust 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
•
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, or I3, or I4
with an aggregate capacity less than or equal to 75 MVA (gross nameplate
rating). Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, or I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 3050 kV
or less, between configurations being considered as radial systems, does not affect
this exclusion.
Rationale: The drafting team has proposed a threshold of 350 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a threetwo step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. Finally, examination of design
considerations that the industry deploys to prevent loop flow through
low voltage systems at the various voltage levels confirms that
protection is implemented to prevent such flows through low voltage
looped systems. A formal white paper is beinghas been prepared to
support this approach and is included with this posting.
•
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Draft 12 – MayAugust 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
•
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, or I3, or I4 and do not
have an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Explanation of changes: Not needed this posting – will explain changes in one place, the background section of the comment form.
•
I1 – Made a non-material semantic change to provide greater clarity as suggested by industry comments.
•
I2 – (1) Split the inclusion into an ‘a’ and ‘b’ as suggested by industry to clarify that this is an ‘or’ statement. This is not
shown in redline as it is strictly a structure change and redlining this would mask the changes made for dispersed power
producing resources. (2) Added the dispersed power producing resources phrase to provide clarity as to the inclusion of
such resources herein and to continue to provide the granularity for these resources noted in FERC Orders 773 and 773-A.
(3) Added a brief rationale for the revision to I2. The text box will be removed from the final filed version of the
definition. The text box language will be placed in the appropriate section(s) of the Reference Document when that
document is revised for Phase 2.
•
I4 – Omitted this as a separate inclusion as it is no longer needed with the inclusion of dispersed power producing
resources in Inclusion I2. Since Inclusion I2 includes what is being referred to as generator interconnection facilities, a
separate inclusion to handle collector systems is not needed. The numbering of the inclusions has been retained so as not
to invalidate software tools developed for the Phase 1 definition.
•
I5 – Made a semantic addition to provide clarity as suggested by industry comments.
•
E1 – Added Note 2 on looped configurations, which provides a floor below which an entity does not have to consider the
loop in its determination of a radial system. Preliminary justification for the value is shown in separate supporting
documents for this posting, and a brief description of the rationale is included in a text box within E1. A formal white
paper will be developed justifying this approach. The language in the text box will be deleted from the final filed definition
and will be included in the appropriate sections of the Reference Document.
o E1 b) and c) – Changed to address directives in Orders 773 and 773-A for generator interconnection facilities.
Draft 12The
– MayAugust
2013
Page in
5 of 5
“…with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating)” language remains
the definition even with the addition of Inclusion I2 as it refers to the aggregate of multiple sites along the radial.
•
E3 – (1) Addressed directive in Orders 773 and 773-A by deleting the ‘or above 100 kV but’ phrasing. (2) Semantic
change replacing ‘retail customer Load’ with ‘retail customers’ to provide clarity as suggested by industry comments.
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall
go become effective on the first day of the second calendar quarter after Board of Trustees adoption or
as otherwise made effective pursuant to the laws of applicable governmental authorities.
Compliance obligations for the Phase 2 definition would begin:
• Twenty-four months after the applicable effective date of the definition (for newly identified
Elements), or
• If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case-by-case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall
go into effectbecome effective on the first day of the second calendar quarter after Board of Trustees
adoption or as otherwise made effective pursuant to the laws of applicable governmental authorities.
Compliance obligations for the Phase 2 definition would begin:
• Twenty-four months after the applicable effective date of the definition (for newly identified
Elements), or
• If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case-by-case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Bulk Electric System Radial Exclusion (E1)
Low Voltage Loop Threshold
Executive Summary
The Project 2010‐17 Standard Drafting Team (SDT) conducted a two‐step study process to yield a
technical justification for the establishment of a voltage threshold below which sub‐100 kV loops do not
affect the application of Exclusion E1. This analysis provides an equally effective and efficient alternative
to address the Federal Energy Regulatory Commission’s (Commission or FERC) directives expressed in
Order No. 773 and 773‐A. The analysis establishes that a 50 kV threshold for sub‐100 kV loops does not
affect the application of Exclusion E1. Furthermore, this approach will ease the administrative burden
on entities to prove that they qualify for an exclusion.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 1
Introduction
In Order No. 773 and 773A, the Commission expressed concerns that facilities operating below 100 kV
may be required to support the reliable operation of the interconnected transmission system. The
Commission also indicated that additional factors beyond impedance must be considered to
demonstrate that looped or networked connections operating below 100 kV need not be considered in
the application of Exclusion E1.1 This document responds to the Commission’s concerns and provides a
technical justification for the establishment of a voltage threshold below which sub‐100 kV equipment
need not be considered in the evaluation of Exclusion E1.
NOTE: This justification does not address whether sub‐ 100 kV systems should be evaluated as Bulk
Electrical System (BES) Facilities. Sub‐ 100 kV systems are already excluded from the BES under the core
definition. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s
interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric
system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission
in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub‐100 kV elements comprising
radial systems and local networks will not be included in the bulk electric system, unless determined
otherwise in the exception process.” Sub‐ 100 kV facilities will only be included as BES Facilities if
justified under the NERC Rules of Procedure (ROP) Appendix 5C Exception Process.Study Methodology
The justification for establishing a lower voltage threshold for application of Exclusion E1 consisted of a
two‐step technical approach:
Step 1: A review was performed to determine the minimum voltage levels that are monitored by
Balancing Authorities, Reliability Coordinators, and Transmission Operators for Interfaces, Paths, and
Monitored Elements. This minimum voltage level reflects a value that industry experts consider
necessary to monitor and facilitate the operation of the Bulk Electric System (BES). This step provided a
technically sound approach to screen for a minimum voltage limit that served as a starting point for the
technical analysis performed in Step 2 of this study.
Step 2: Technical studies modeling the physics of loop flows through sub‐100 kV systems were
performed to establish which voltage level, while less than 100 kV, should be considered in the
evaluation of Exclusion E1.
1
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,
Order No. 773, 141 FERC ¶ 61,236 at P155, n.139 (2012); order on reh’g, Order No. 773‐A, 143 FERC ¶ 61,053
(2013).
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 2
Radial Systems Exclusion (E1)
The proposed definition (first posting) of radial systems in the Phase 2 BES Definition (Exclusion E1) was:
A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV
or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2 and I3, with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in
Inclusions I2 and I3, with an aggregate capacity of non‐retail generation less than or equal
to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on prints or
one‐line diagrams for example, does not affect this exclusion.
Note 2 ‐ The presence of a contiguous loop, operated at a voltage level of 30 kV or less2,
between configurations being considered as radial systems, does not affect this exclusion.
2
The first posting of this Phase 2 definition used a threshold of 30 kV; however as a result of the study work
described in this paper, the SDT has revised the threshold to 50 kV for subsequent industry consideration.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 3
STEP 1 – Establishment of Minimum Monitored Regional Voltage Levels
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The groupings of these elements have different names: for instance,
Paths in the Western Interconnection; Interfaces or Flowgates in the Eastern Interconnection; or
Monitored Elements in the Electric Reliability Council of Texas (ERCOT). Nevertheless, they all constitute
element groupings that operating entities (Reliability Coordinators, Balancing Authorities, and
Transmission Operators) monitor because they understand that they are necessary to ensure the
reliable operation of the interconnected transmission system under diverse operating conditions.
To provide information in determining a voltage level where the presence of a contiguous loop between
system configurations may not affect the determination of radial systems under Exclusion E1 of the BES
definition, voltage levels that are monitored on major Interfaces, Flowgates, Paths, and ERCOT
Monitored Elements were examined. This examination focused on elements owned and operated by
entities in the contiguous United States. The objective was to identify the lowest monitored voltage
level on these key element groupings. The lowest monitored line voltage on the major element
groupings provides an indication of the lower limit which operating entities have historically believed
necessary to ensure the reliable operation of the interconnected transmission system. The results of
this analysis provided a starting point for the technical analysis which was performed in Step 2 of this
study.
Step 1 Approach
Each Region was requested to provide the key groupings of elements they monitor to ensure reliable
operation of the interconnected transmission system. This list, contained in Appendix 1, was reviewed
to identify the lowest voltage element in the major element groupings monitored by operating entities
in the eight Regions. Identification of this lowest voltage level served as a starting point to begin a
closer examination into the voltage level where the presence of a contiguous loop should not affect the
evaluation of radial systems under Exclusion E1 of the BES definition.
Step 1 Results
An examination of the line listings of the U.S. operating entities revealed that the majority of operating
entities do not monitor elements below 69 kV as shown in Table 1. However, in some instances
elements with line voltages of 34.5 kV were included in monitored element groupings. In no instance
was a transmission line element below 34.5 kV included in the monitored element groupings.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 4
Region
FRCC
MRO
Key Monitored Element Grouping
Southern Interface
NDEX
Total East PJM (Rockland Electric) – Hudson Valley
(Zone G)1
MWEX
VACAR IDC2
SPSNORTH_STH
Valley Import GTL
Path 52 Silver Peak – Control 55 kV
NPCC
Lowest Line Element Voltage
115
69
34.5
69
RFC
115
SERC
115
SPP RE
138
TRE
55
WECC
Notes:
1. Two interfaces in NPCC/NYISO have lines with 34.5 kV elements.
2. The TVA area in SERC was not included in the tables attached to this report; however, a review
of the Flowgates in TVA revealed monitored elements no lower than 115 kV.
Table 1: Lowest Line Element Voltage Monitored by Region
In a few rare occasions there were transformer elements with low‐side windings lower than 30 kV
included in the key monitored element groupings as shown in Table 2.
Region
Interface
Element
Voltage (kV)
NPCC/NYISO
(Farmtn 34.5/115kV&12/115 kV) #4
34.5/115 & 12/115
SOTHNGTN 5X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐5X)
SOTHNGTN 6X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐6X)
SOTHNGTN 11X ‐ Southington 115 kV
/27.6 kV Transformer (4C‐11X)
12/115
WEST CENTRAL: Genesee
(Zone B) – Central (Zone C)
New England ‐ Southwest
Connecticut
NPCC/ISO‐NE
115/13.8
115/13.8
115/27.6
Table 2: Lowest Line Transformer Element Voltages Monitored by Region
Upon closer investigation, for New England’s Southwest Connecticut interface, it was determined that
the inclusion of these elements was the result of longstanding, historical interface definitions and not
for the purpose of addressing BES reliability concerns. Transformers serving lower voltage networks
continue to be included based on familiarity with the existing interface rather than a specific technical
concern. These transformers could be removed from the interface definition with no impact on the
reliability of the interconnected transmission system. For the New York West Central interface, the low
voltage element was included because the interface definition included boundary transmission lines
between Transmission Owner control areas; hence, it was included for completeness to measure the
power flow from one Transmission Owner control area to the other Transmission Owner control area.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 5
Further examination of the information provided by the eight NERC regions revealed that half of the
Regions only monitor transmission line elements with voltages above the 100 kV level. The other four
Regions, NPCC, RFC, MRO, and WECC, monitor transmission line elements below 100 kV as part of key
element groupings. However, in each of these cases, the number of below 100 kV transmission line
elements comprised less than 2.5% of the total monitored key element groupings. Figures 1 and 2
below depict the results of Step 1 of this study.
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 1: Voltage as Percent of Monitored Elements
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 6
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 2: Voltage as Percent of Monitored Elements per Region
Step 1 Conclusion
The results of this Step 1 study regarding regional monitoring levels resulted in a determination that 30
kV was a reasonable voltage level to initiate the sensitivity analysis conducted in Step 2 of this study.
This value is below any of the regional monitoring levels.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 7
STEP 2 ‐ Load Flows and Technical Considerations
The threshold of 30 kV was established in Step 1 as a reasonable starting point to initiate the technical
sensitivity analysis in Step 2 of this study. The purpose of this step was to determine if there is a
technical justification to support a voltage threshold for the purpose of determining whether facilities
can be considered to be radial under the BES Definition Exclusion E1. If the resulting voltage threshold
was deemed appropriate through technical study efforts, then contiguous loop connections operated at
voltages below this value would not preclude the use of Exclusion E1. Conversely, contiguous loops
connecting radial lines at voltages above this kV value would negate the ability for an entity to use
Exclusion E1 for the subject facilities.
This study focused on two typical configurations: a distribution loop and a sub‐transmission loop. The
goal was to use these configurations and adjust the various loads, voltages, flows, and impedances to
determine the level at which single contingencies on the transmission system would cause flows on the
low voltage system. These studies provided the low voltage floor that can be used as a consideration for
BES exclusion E1.
NOTE: This justification does not address whether sub‐ 100 kV systems should be evaluated as Bulk
Electrical System (BES) Facilities. Sub‐ 100 kV systems are already excluded from the BES under the core
definition. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s
interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric
system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission
in Order 773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub‐100 kV elements comprising
radial systems and local networks will not be included in the bulk electric system, unless determined
otherwise in the exception process.” Sub‐ 100 kV facilities will only be included as BES Facilities if
justified under the NERC Rules of Procedure (ROP) Appendix 5C Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 8
Analytical Approach – Distribution Circuit Loop Example
The Project 2010‐17 SDT sought to examine the interaction and relative magnitude of flows on the 100
kV and above Facilities of the electric system and those of any underlying low voltage distribution loops.
While not the determining factor leading to this study’s recommendation, line outage distribution
factors (LODF) were a useful tool in understanding the relationship between underlying systems and the
BES elements. It illustrated the relative scale of interaction between the BES and the lower voltage
systems and its review was a consideration when the study analysis was performed. As an example,
the SDT considered a system similar to the one depicted in Figure 3 below. In this simplified depiction of
a portion of an electric system, two radial 115 kV lines emanate from 115 kV substations A and B to
serve distribution loads via 115 kV/distribution transformers at stations C and D. Stations C and D are
“looped” together via either a distribution bus tie (zero impedance) or a feeder tie (modeled with typical
distribution feeder impedances).
Station A
Station B
To 115 kV
System
To 115 kV
System
Station D
Station C
Distribution
Circuit Tie
Load 2
Load 3
Figure 3: Example Radial Systems with Low Voltage Distribution Loop
With the example system, the SDT conducted power flow simulations to assess the performance of the
power system under single contingency outages of the line between stations A and B. The analyses
determined the LODF which represent the portion of the high voltage transmission flow that would
distribute across the low voltage distribution circuit or bus ties under a single contingency outage of the
line between stations A and B. To the extent that the LODF values were negligible, this indicated a minor
or insignificant contribution of the distribution loops to the operation of the high voltage system. But,
more importantly, the analyses determined whether any instances of power flow reversal, i.e., resultant
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 9
flow delivered into the BES, would occur during contingent operating scenarios. Instances of flow
reversal into the BES would indicate that the underlying distribution looped system is exhibiting
behavior similar to a sub‐transmission or transmission system, which would call into question the
applicability of radial exclusion E1.
The study work in this approach examined the sensitivity of parallel circuit flow on the distribution
elements to the size of the distribution transformers, the operating voltage of distribution delivery buses
at stations C and D and the strength of the transmission network serving stations A and B as manifested
in the variation of the transmission network transfer impedance used in the model.
In order to simply, yet accurately, represent this low voltage loop scenario between two radial circuits, a
Power System Simulator for Engineering (PSSE) model was created. Elements represented in this model
included the following:
Radial 115 kV lines from station A to station C and station B to station D;
Interconnecting transmission line from station A to station B;
Distribution transformers between 115 kV and the distribution buses at stations C and D;
Feeder tie impedance to represent a feeder tie (or zero impedance bus tie) between distribution
buses at stations C and D;
Network equivalent source impedances at source stations A and B;
Transfer impedance equivalent between stations A and B, representing the strength of the
interconnected transmission network.
Within this model, parameters were modified to simulate differences in the length and impedance of
the transmission lines, amount of distribution load, strength of the transmission network supplying
stations A and B, size of the distribution transformers, and the character of the bus or feeder tie at
distribution Stations C and D.
Distribution Model Simulation
Table 3 below illustrates the domain of the various parameters that were simulated in this distribution
circuit loop scenario. A parametric analysis was performed using all combinations of variables shown in
each column of Table 3.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 10
Trans KV
Trans Length
Dist KV
Dist Length
XFMR MVA
115
10 miles
30 miles
12.5
23
34.5
46
0 (bus tie)
2 miles
5 miles
10
20
40
Dist Load
% rating
40
80
Z Transfer
Strong
Medium
Weak
Notes:
1. The “medium” value for transfer impedances was derived from an actual example system in the
northeastern US. This was deemed to be representative of a network with typical, or medium,
transmission strength. Variations of a stronger (more tightly coupled) and a weaker transmission network
were selected for the “strong” and “weak” cases, respectively. Impedance values of X=0.54%, X=1.95%,
and X=4.07% were applied for the strong, medium and weak cases, respectively.
Table 3: Model Parameters Varied
The model was exercised in a series of cases simulating a power transfer on the 115 kV line3 from station
A to station B of slightly more than 100 MW. Loads and impedances were simulated at the location
shown in Figure 5 of Appendix 2. Two load levels were used in each scenario: 40% of the rating of the
distribution transformer and 80% of the rating. Distribution transformer ratings were varied in three
steps: 10 MVA, 20 MVA, and 40 MVA. Finally, the strength of the interconnected transmission network
was varied in three steps representing a strong, medium, and weak transmission network. The choices
of transfer impedance were based on typical networks in use across North America. A specific model
from the New England area of the United States yielded an actual transfer impedance of 0.319 +
j1.954%. This represents the ’medium’ strength transmission system used in the analyses. The other
values used in the study are minimum (’strong’) and maximum (’weak’) ends of the typical range of
transfer impedances for 115 kV systems interconnected to the Bulk Electric System of North America.
Distribution feeder connections were simulated in three different ways, first with zero impedance
between the distribution buses at stations C and D, second with a 2‐mile feeder connection with typical
overhead conductor, and third with a 5‐mile connection.
Distribution Model Results
23 kV Distribution System
The results show LODFs ranging from a low of 0.2% to a high of 6.7%. In all of the cases, the direction of
power flow to the radial lines was toward stations C and D. In other words, there were no instances of
flow reversal from the distribution system back to the 115 kV transmission system.
The lowest LODF was found in the case with the smallest distribution transformers (10 MVA), the 5‐mile
distribution circuit tie, and the strong transmission transfer impedance. The case with the highest LODF
3
The threshold voltage of 115 kV provides conservative results. At a higher voltage, such as 230 kV, the reflection
of distribution impedance to the transmission system is significantly larger, and hence, the amount of distribution
power flow will be much smaller.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 11
was that which used the largest distribution transformers (40 MVA) with the lightest load and the use of
a zero‐impedance bus tie between the two distribution stations.
12.5 kV Distribution System
As compared to the simulations using the 23 kV distribution system, the 12.5 kV system model yielded
far lower LODF values. This result is reasonable, as the reflection of impedances on a 12.5 kV
distribution system will be nearly four times as large as those for a 23 kV distribution system, and the
transformer sizes in use at the 12.5 kV class are generally smaller, i.e., higher impedance. As with the
cases simulated for the 23 kV system, the 12.5 kV system exhibited a power flow direction in the radial
line terminals at stations A and B in the direction of the distribution stations C and D; no flow reversal
was seen in any of the contingency cases.
Given the lower voltage of the distribution system, the cases studied at this low voltage level were
limited to the scenario with the high transfer impedance value (’weak’ transmission case). This is a
conservative assumption as all cases with lower transfer impedance will yield far lower LODF values.
With that, the range of LODF values was found to be 1.0% to 6.7%. When compared with the 23 kV
system results in the weak transmission case, the range of LODF values was 1.8% to 6.7%. Higher LODF
values were found in the cases with the largest transformer size, which is to be expected.
Table 4 below provides a sample of the results of the various simulations that were conducted. The full
collection of results is provided in Appendix 3.
Case
D, KV
623a5
623a5pk
633b0pk
723c0
723c5pk
823b0
823c0
812a5
812b0
812b5pk
812c0
834a5pk
834b5pk
834d0
834d0pk
846e0
846e2
846e5
23
23
23
23
23
23
23
12.5
12.5
12.5
12.5
34.5
34.5
34.5
34.5
46
46
46
Z xfer
strong
strong
strong
medium
medium
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
ZDist
5 mi
5 mi
0
0
5 mi
0
0
5 mi
0
5 mi
0
5 mi
5 mi
0
0
0
2 mi
5 mi
XFMR MVA
Load, MW
LODF
10
10
20
40
40
20
40
10
20
20
40
10
20
40
40
50
50
50
4
8
16
16
32
8
16
4
8
16
16
8
16
16
32
16
20
20
0.2%
0.3%
0.4%
3.4%
1.6%
3.8%
6.7%
1.0%
3.8%
1.3%
6.7%
1.7%
3.0%
8.9%
8.7%
10.3%
9.0%
7.4%
Table 4: Select Sample of Study Results for Distribution Scenario
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 12
34.5 kV and 46 kV Distribution Systems
As with the analysis done for the 12.5 kV system, a conservative transfer impedance value, that of the
’weak’ transmission network, was used in selecting the transfer impedance to be used in the simulations
at 34.5 kV and 46 kV. With this conservative parameter, the simulation results show distribution factors
(LODF) ranging from a low of 1.7% to a high of 10.3%. In all of the cases, the direction of power flow to
the radial lines remained from stations A and B toward stations C and D. In other words, there were no
instances of flow reversal from the distribution system back to the 115 kV transmission system.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 13
Analytical Approach – Sub‐transmission Example
In addition to the distribution circuit loop example described above, the study examined the
performance of systems typically described as ’sub‐transmission’. The study sought to examine the
interaction and relative magnitude of flows on the 100 kV and above Facilities of the interconnected
transmission system and those of the underlying parallel sub‐transmission facilities. The study
considered a system similar to the one depicted in Figure 4 below. In this simplified depiction of a
portion of a transmission and sub‐transmission system, a 40‐mile transmission line connecting two
sources with transfer impedance between the two sources representing the parallel transmission
network. Each source also supplies a 10‐mile transmission line with a load tap at the mid‐point of the
line, each serving a load of 16 MW. At the end of each of these lines is a step‐down transformer to the
sub‐transmission voltage, where an additional load is served. The two sub‐transmission stations are
connected by a 25‐mile sub‐transmission tie line. Loads and impedances were simulated at the location
shown in Figure 6 of Appendix 2.
Figure 4: Example Radial Systems with Sub‐transmission Loop
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 14
Given this example sub‐transmission system, a PSSE model was created to simulate the power flow
characteristics of the system during a contingency outage of the transmission line between stations A
and B. Within this model, parameters were modified to simulate differences in the amount of load
being served, transformer size and the amount of pre‐contingent power flow on the transmission line.
All simulations were performed with a transfer impedance representative of a ‘weak’ transmission
network.
Sub‐transmission Model Simulation
Simulations were performed for each sub‐transmission voltage (34.5 kV, 46 kV, 55 kV, and 69 kV) using a
transmission voltage of 115 kV. This analysis identified the potential for power flowing back to the
transmission system only for sub‐transmission voltages of 55 kV and 69 kV. Sensitivity analysis was
performed using higher transmission voltages to confirm that cases with 115 kV transmission are the
most conservative. Therefore, it was not necessary to perform sensitivity analysis for sub‐transmission
voltages of 34.5 kV and 46 kV for transmission voltages higher than 115 kV.
Table 5 below illustrates the domain of the various parameters that were simulated in this sub‐
transmission circuit loop scenario. A parametric analysis was performed using combinations of variables
shown in each column of Table 5.
Trans KV
Trans Length Sub‐T KV
115
40 miles
Sensitivity Analyses:
138
40 miles
161
230
34.5
46
55
69
55
69
Sub‐T Length XFMR MVA
25 miles
25 miles
40
50
60
50
60
Dist Load
% rating
40
40
Trans MW
Preload
115
115
135
150
220
Table 5: Model Parameters and Sensitivities
Sub‐transmission Model Results
115 kV Transmission System with 34.5‐69 kV Sub‐transmission
The results for cases depicting a 115 kV transmission system voltage and ranges of 34.5 kV to 69 kV sub‐
transmission voltages show line outage distribution factors (LODF) in the range of 9% to slightly higher
than 20%. Several cases show a reversal of power flow in the post‐contingent system such that power
flow is delivered from the sub‐transmission system into the 115 kV BES. The worst case is found in the
69 kV sub‐transmission voltage class. This result is as expected, given that the impedance of the 69 kV
sub‐transmission system is less than the impedances of lower voltage systems.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 15
138 kV and 161 kV Transmission Systems with 55‐69 kV Sub‐transmission
The results for cases of 138 kV and 161 kV transmission system voltages supplying sub‐transmission
voltages of 55 kV and 69 kV show LODFs ranging from 9% to 16% These cases also result in reversal of
power flows in the post‐contingent system such that power flow is delivered from the sub‐transmission
system into the 115 kV BES.
230 kV Transmission System with 55‐69 kV Sub‐transmission
By simulating a higher BES source voltage of 230 kV paired with sub‐transmission voltages of 55 kV and
69 kV, the transformation ratio is sufficiently large to result in a significant increase to the reflected sub‐
transmission system impedance. Therefore, in these cases, LODFs range from 5% to 7%, and these cases
also show no reversal of power flow toward the BES in the post‐contingent system.
Table 6 below provides a sample of the results of the various simulations that were conducted. All
results are provided in Appendix 3.
Case
T, KV
S‐T, KV
834d25
846e25
855e25
869f25
855e25‐138
855e25‐138’
869f25‐138
869f25‐138’
855e25‐161
855e25‐161’
869f25‐161
869f25‐161’
855e25‐230
855e25‐230’
869f25‐230
869f25‐230’
115
115
115
115
138
138
138
138
161
161
161
161
230
230
230
230
34.5
46
55
69
55
55
69
69
55
55
69
69
55
55
69
69
Trans Pre‐
load, MW
115
114
112
110
114
134
112
132
114
155
113
153
116
219
116
218
XFMR
MVA
40
50
50
60
50
60
60
60
50
60
60
60
50
60
60
60
Load, MW
LODF
20
20
20
24
20
20
24
24
20
20
24
24
20
20
24
24
9.4%
13.3%
15.7%
20.3%
11.7%
11.9%
15.6%
15.8%
9.1%
9.2%
12.5%
12.6%
4.9%
5.0%
7.0%
7.0%
Flow Rev
to BES?
Yes
Yes
Yes
Yes
Yes
Yes
Table 6: Select Sample of Study Results for Sub‐transmission Scenario
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 16
Step 2 Conclusion
Step 2 of this analysis concludes that 50 kV is the appropriate low voltage loop threshold below which
sub‐100 kV loops should not affect the application of Exclusion E1. Simulations of power flows for the
cases modeled in this study show there is no power flow reversal into the BES when circuit loop
operating voltages are below 50 kV. This study also finds, for loop voltages above 50 kV, certain cases
result in power flow toward the BES. Therefore, the study concludes that low voltage circuit loops
operated below 50 kV should not affect the application of Exclusion E1.
Study Conclusion
The Project 2010‐17 SDT conducted a two‐step study process to yield a technical justification for the
establishment of a voltage threshold below which sub‐100 kV loops should not affect the application of
Exclusion E1. This analysis provides an equally effective and efficient alternative to address the
Commission’s directives expressed in Order No. 773 and 773‐A. It establishes that a 50 kV threshold for
sub‐100 kV loops does not affect the application of Exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 17
Appendix 1
The information contained in Appendix 1 could be confidential and sensitive to entities and regional
organizations and is removed from this draft report.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 18
Appendix 2
Figure 5: Example Radial Systems with Low Voltage Distribution Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 19
Figure 6: Example Radial Systems with Sub‐transmission Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 20
Appendix 3
Case
ZL
Ztr
Zln1‐4
Zdist
(total)
ZT1‐4
L1, L4
L2, L3
X‐‐‐‐‐‐‐ HV Line "L" in‐of‐service ‐‐‐‐‐‐‐X
PL
Pln1
Pln2
Pln3
Pln4
X‐ HV Line "L" out‐of‐service ‐X
Pln1'
Pln2'
Pln3'
Pln4'
df
(Z/MVA)
23 kV Base Cases
623a0
10 mi
0.10xZL
15 mi
0
10%/10
4.0
4.0
110.7
10.9
6.9
1.1
5.1
11.2
7.2
0.8
4.8
0.003
623a2
10 mi
0.10xZL
15 mi
2 mi
10%/10
4.0
4.0
110.7
10.7
6.7
1.4
5.4
10.9
6.9
1.1
5.1
0.002
623a5
10 mi
0.10xZL
15 mi
5 mi
10%/10
4.0
4.0
110.7
10.3
6.3
1.7
5.7
10.5
6.5
1.5
5.5
0.002
623a0pk
10 mi
0.10xZL
15 mi
0
10%/10
8.0
8.0
111.4
19.0
10.9
5.1
13.1
19.3
11.2
4.8
12.8
0.003
623a2pk
10 mi
0.10xZL
15 mi
2 mi
10%/10
8.0
8.0
111.4
18.7
10.7
5.4
13.4
18.9
10.9
5.1
13.1
0.002
623a5pk
10 mi
0.10xZL
15 mi
5 mi
10%/10
8.0
8.0
111.5
18.3
10.3
5.7
13.7
18.6
10.5
5.5
13.5
0.003
623b0
10 mi
0.10xZL
15 mi
0
10%/20
8.0
8.0
111.1
21.7
13.7
2.3
10.3
22.3
14.2
1.8
9.8
0.005
623b2
10 mi
0.10xZL
15 mi
2 mi
10%/20
8.0
8.0
111.2
20.7
12.7
3.3
11.3
21.2
13.2
2.9
10.9
0.004
623b5
10 mi
0.10xZL
15 mi
5 mi
10%/20
8.0
8.0
111.3
19.7
11.7
4.3
12.3
20.1
12.1
4.0
12.0
0.004
623b0pk
10 mi
0.10xZL
15 mi
0
10%/20
16.0
16.0
112.6
37.8
21.7
10.3
26.3
38.3
22.3
9.7
25.8
0.004
623b2pk
10 mi
0.10xZL
15 mi
2 mi
10%/20
16.0
16.0
112.7
36.7
20.7
11.3
27.3
37.2
21.2
10.9
26.9
0.004
623b5pk
10 mi
0.10xZL
15 mi
5 mi
10%/20
16.0
16.0
112.8
35.7
19.7
12.3
28.4
36.1
20.1
12.0
28.0
0.004
623c0
10 mi
0.10xZL
15 mi
0
10%/40
16.0
16.0
112.2
42.7
26.6
5.4
21.4
43.7
27.7
4.3
20.3
0.009
623c2
10 mi
0.10xZL
15 mi
2 mi
10%/40
16.0
16.0
112.5
39.6
23.6
8.4
24.4
40.4
24.4
7.7
23.7
0.007
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 21
623c5
10 mi
0.10xZL
15 mi
5 mi
10%/40
16.0
16.0
112.7
37.3
21.3
10.8
26.8
37.8
21.8
10.3
26.3
0.004
623c0pk
10 mi
0.10xZL
15 mi
0
10%/40
32.0
32.0
115.1
74.9
42.8
21.2
53.3
76.0
43.9
20.2
52.2
0.010
623c2pk
10 mi
0.10xZL
15 mi
2 mi
10%/40
32.0
32.0
115.4
71.8
39.7
24.3
56.4
72.6
40.5
23.6
55.6
0.007
623c5pk
10 mi
0.10xZL
15 mi
5 mi
10%/40
32.0
32.0
115.6
69.4
37.4
26.7
58.8
70.0
37.9
26.2
58.3
0.005
723a0
10 mi
0.36xZL
15 mi
0
10%/10
4.0
4.0
108.3
10.9
6.9
1.1
5.1
11.9
7.9
0.1
4.1
0.009
723a2
10 mi
0.36xZL
15 mi
2 mi
10%/10
4.0
4.0
108.3
10.6
6.6
1.4
5.4
11.5
7.5
0.5
4.5
0.008
723a5
10 mi
0.36xZL
15 mi
5 mi
10%/10
4.0
4.0
108.4
10.3
6.3
1.8
5.8
11.1
7.1
1.0
5.0
0.007
723a0pk
10 mi
0.36xZL
15 mi
0
10%/10
8.0
8.0
110.4
18.9
10.9
5.1
13.1
20.0
12.0
4.0
12.1
0.010
723a2pk
10 mi
0.36xZL
15 mi
2 mi
10%/10
8.0
8.0
110.5
18.6
10.6
5.4
13.4
19.6
11.6
4.4
12.5
0.009
723a5pk
10 mi
0.36xZL
15 mi
5 mi
10%/10
8.0
8.0
110.6
18.3
10.3
5.7
13.7
19.1
11.1
4.9
12.9
0.007
723b0
10 mi
0.36xZL
15 mi
0
10%/20
8.0
8.0
109.7
21.6
13.6
2.4
10.4
23.6
15.6
0.4
8.4
0.018
723b2
10 mi
0.36xZL
15 mi
2 mi
10%/20
8.0
8.0
110.0
20.6
12.6
3.4
11.4
22.3
14.3
1.7
9.8
0.015
723b5
10 mi
0.36xZL
15 mi
5 mi
10%/20
8.0
8.0
110.2
19.7
11.7
4.4
12.4
21.0
13.0
3.1
11.1
0.012
723b0pk
10 mi
0.36xZL
15 mi
0
10%/20
16.0
16.0
114.0
37.8
21.8
10.2
26.3
39.9
23.8
8.2
24.2
0.018
723b2pk
10 mi
0.36xZL
15 mi
2 mi
10%/20
16.0
16.0
114.3
36.8
20.8
11.3
27.3
38.5
22.5
9.6
25.6
0.015
723b5pk
10 mi
0.36xZL
15 mi
5 mi
10%/20
16.0
16.0
114.5
35.8
19.8
12.3
28.3
37.2
21.1
10.9
27.0
0.012
723c0
10 mi
0.36xZL
15 mi
0
10%/40
16.0
16.0
112.6
42.7
26.7
5.3
21.3
46.5
31.4
1.6
17.6
0.034
723c2
10 mi
0.36xZL
15 mi
2 mi
10%/40
16.0
16.0
113.5
39.7
23.7
8.4
24.4
42.4
26.4
5.7
21.7
0.024
723c5
10 mi
0.36xZL
15 mi
5 mi
10%/40
16.0
16.0
114.1
37.4
21.4
10.7
26.7
39.3
23.3
8.8
24.8
0.017
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 22
723c0pk
10 mi
0.36xZL
15 mi
0
10%/40
32.0
32.0
121.2
75.5
43.4
20.7
52.7
79.5
47.4
16.7
48.7
0.033
723c2pk
10 mi
0.36xZL
15 mi
2 mi
10%/40
32.0
32.0
122.0
72.2
40.1
23.9
55.9
75.2
43.1
21.1
53.1
0.025
723c5pk
10 mi
0.36xZL
15 mi
5 mi
10%/40
32.0
32.0
122.7
69.8
37.7
26.4
58.5
71.8
39.7
24.4
56.5
0.016
823a0
10 mi
0.75xZL
15 mi
0
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
823a2
10 mi
0.75xZL
15 mi
2 mi
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
823a5
10 mi
0.75xZL
15 mi
5 mi
10%/10
4.0
4.0
106.4
10.2
62.0
1.8
5.8
11.9
7.9
0.2
4.2
0.016
823a0pk
10 mi
0.75xZL
15 mi
0
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
823a2pk
10 mi
0.75xZL
15 mi
2 mi
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.6
12.6
3.5
11.5
0.018
823a5pk
10 mi
0.75xZL
15 mi
5 mi
10%/10
8.0
8.0
109.8
18.3
10.3
5.7
13.8
20.0
12.0
4.0
12.1
0.015
823b0
10 mi
0.75xZL
15 mi
0
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
823b2
10 mi
0.75xZL
15 mi
2 mi
10%/20
8.0
8.0
108.8
20.6
12.6
3.4
11.4
24.0
16.0
0.1
8.1
0.031
823b5
10 mi
0.75xZL
15 mi
5 mi
10%/20
8.0
8.0
109.2
19.6
11.6
4.4
12.4
22.3
14.3
1.8
9.8
0.025
823b0pk
10 mi
0.75xZL
15 mi
0
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
823b2pk
10 mi
0.75xZL
15 mi
2 mi
10%/20
16.0
16.0
115.7
36.9
20.8
11.2
27.2
40.4
24.4
7.7
23.7
0.030
823b5pk
10 mi
0.75xZL
15 mi
5 mi
10%/20
16.0
16.0
116.2
35.9
19.8
12.2
28.2
38.7
22.7
9.4
25.5
0.024
823c0
10 mi
0.75xZL
15 mi
0
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
823c2
10 mi
0.75xZL
15 mi
2 mi
10%/40
16.0
16.0
114.4
39.7
23.7
8.3
24.3
45.4
29.3
2.8
18.8
0.050
823c5
10 mi
0.75xZL
15 mi
5 mi
10%/40
16.0
16.0
115.5
37.4
21.4
10.6
26.7
41.4
25.4
6.8
22.8
0.035
823c0pk
10 mi
0.75xZL
15 mi
0
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
823c2pk
10 mi
0.75xZL
15 mi
2 mi
10%/40
32.0
32.0
128.2
72.7
40.6
23.5
55.6
78.9
48.6
17.4
49.5
0.048
823c5pk
10 mi
0.75xZL
15 mi
5 mi
10%/40
32.0
32.0
129.3
70.1
38.0
26.1
58.2
74.5
42.4
21.8
53.9
0.034
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 23
Sensitivity to Length of Lines 1‐4
723a0_30
10 mi
0.36xZL
30 mi
0
10%/10
4.0
4.0
108.3
10.8
6.8
1.2
5.2
11.8
7.8
0.2
4.2
0.009
723a2_30
10 mi
0.36xZL
30 mi
2 mi
10%/10
4.0
4.0
108.4
10.5
6.5
1.5
5.5
11.4
7.4
0.6
4.6
0.008
723a5_30
10 mi
0.36xZL
30 mi
5 mi
10%/10
4.0
4.0
108.5
10.2
6.2
1.8
5.8
11.0
7.0
1.0
5.0
0.007
Selected 34.5 kV cases
834a0
10 mi
0.75xZL
15 mi
0
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
834a2
10 mi
0.75xZL
15 mi
2 mi
10%/10
4.0
4.0
106.1
10.7
6.7
1.3
5.3
12.7
8.7
‐0.7
3.3
0.019
834a5
10 mi
0.75xZL
15 mi
5 mi
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
834a0pk
10 mi
0.75xZL
15 mi
0
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
834a2pk
10 mi
0.75xZL
15 mi
2 mi
10%/10
8.0
8.0
109.6
18.8
10.8
5.2
13.3
20.8
12.8
3.2
11.2
0.018
834a5pk
10 mi
0.75xZL
15 mi
5 mi
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.5
12.5
3.5
11.5
0.017
834b0
10 mi
0.75xZL
15 mi
0
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
834b2
10 mi
0.75xZL
15 mi
2 mi
10%/20
8.0
8.0
108.6
21.1
13.1
2.9
10.9
24.8
16.8
‐0.7
7.3
0.034
834b5
10 mi
0.75xZL
15 mi
5 mi
10%/20
8.0
8.0
108.9
20.5
12.5
3.5
11.5
23.8
15.8
0.3
8.3
0.030
834b0pk
10 mi
0.75xZL
15 mi
0
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
834b2pk
10 mi
0.75xZL
15 mi
2 mi
10%/20
16.0
16.0
115.5
37.4
21.4
10.7
26.7
41.3
25.3
6.8
22.8
0.034
834b5pk
10 mi
0.75xZL
15 mi
5 mi
10%/20
16.0
16.0
115.8
36.8
20.7
11.3
27.3
40.3
24.2
7.8
23.9
0.030
834c0
10 mi
0.75xZL
15 mi
0
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
834c2
10 mi
0.75xZL
15 mi
2 mi
10%/40
16.0
16.0
113.8
41.2
25.2
6.9
22.9
47.8
31.7
0.4
16.4
0.058
834c5
10 mi
0.75xZL
15 mi
5 mi
10%/40
16.0
16.0
114.6
39.5
23.5
8.5
24.6
45.0
29.0
3.2
19.2
0.048
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 24
834c0pk
10 mi
0.75xZL
15 mi
0
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
834c2pk
10 mi
0.75xZL
15 mi
2 mi
10%/40
32.0
32.0
127.5
74.2
42.1
21.9
54.0
81.5
49.4
14.7
46.8
0.057
834c5pk
10 mi
0.75xZL
15 mi
5 mi
10%/40
32.0
32.0
128.3
72.4
40.3
23.8
55.8
78.5
46.4
17.9
49.9
0.048
834d0
10 mi
0.75xZL
15 mi
0
7%/40
16.0
16.0
111.6
46.3
30.3
1.7
17.7
56.2
40.1
‐8.1
7.9
0.089
834d2
10 mi
0.75xZL
15 mi
2 mi
7%/40
16.0
16.0
112.8
43.6
27.6
4.4
20.4
51.8
35.8
‐3.6
12.4
0.073
834d5
10 mi
0.75xZL
15 mi
5 mi
7%/40
16.0
16.0
113.9
41.1
25.1
7.0
23.0
47.6
31.6
0.6
16.6
0.057
834d0pk
10 mi
0.75xZL
15 mi
0
7%/40
32.0
32.0
124.9
80.0
47.9
16.2
48.2
90.9
58.8
5.3
37.3
0.087
834d2pk
10 mi
0.75xZL
15 mi
2 mi
7%/40
32.0
32.0
126.3
77.0
44.9
19.2
51.2
86.1
54.0
10.2
42.2
0.072
834d5pk
10 mi
0.75xZL
15 mi
5 mi
7%/40
32.0
32.0
127.5
74.2
42.1
22.0
54.1
81.4
49.3
15.0
47.0
0.056
Selected 12.47 kV cases
812a0
10 mi
0.75xZL
15 mi
0
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
812a2
10 mi
0.75xZL
15 mi
2 mi
10%/10
4.0
4.0
106.4
10.1
6.1
1.9
5.9
11.6
7.6
0.4
4.4
0.014
812a5
10 mi
0.75xZL
15 mi
5 mi
10%/10
4.0
4.0
106.7
9.4
5.4
2.6
6.6
10.5
6.5
1.5
5.5
0.010
812a0pk
10 mi
0.75xZL
15 mi
0
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
812a2pk
10 mi
0.75xZL
15 mi
2 mi
10%/10
8.0
8.0
109.9
18.1
10.1
5.9
13.9
19.7
11.7
4.3
12.4
0.015
812a5pk
10 mi
0.75xZL
15 mi
5 mi
10%/10
8.0
8.0
110.2
17.5
9.5
6.5
14.5
18.6
10.6
5.5
13.5
0.010
812b0
10 mi
0.75xZL
15 mi
0
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
812b2
10 mi
0.75xZL
15 mi
2 mi
10%/20
8.0
8.0
109.4
19.2
11.2
4.8
12.8
21.7
13.6
2.5
10.5
0.023
812b5
10 mi
0.75xZL
15 mi
5 mi
10%/20
8.0
8.0
110.0
17.9
9.9
6.1
14.1
19.4
11.4
4.7
12.7
0.014
812b0pk
10 mi
0.75xZL
15 mi
0
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 25
812b2pk
10 mi
0.75xZL
15 mi
2 mi
10%/20
16.0
16.0
116.4
35.4
19.4
12.6
28.6
38.0
22.0
10.2
26.2
0.022
812b5pk
10 mi
0.75xZL
15 mi
5 mi
10%/20
16.0
16.0
117.0
34.1
18.0
14.0
30.0
35.6
19.6
12.6
28.6
0.013
812c0
10 mi
0.75xZL
15 mi
0
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
812c2
10 mi
0.75xZL
15 mi
2 mi
10%/40
16.0
16.0
115.9
36.6
20.6
11.5
27.5
40.0
24.0
8.3
24.3
0.029
812c5
10 mi
0.75xZL
15 mi
5 mi
10%/40
16.0
16.0
116.8
34.4
18.4
13.7
29.7
36.2
20.2
12.0
28.0
0.015
812c0pk
10 mi
0.75xZL
15 mi
0
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
812c2pk
10 mi
0.75xZL
15 mi
2 mi
10%/40
32.0
32.0
129.7
69.2
37.1
27.1
59.1
73.0
40.9
23.5
55.5
0.029
812c5pk
10 mi
0.75xZL
15 mi
5 mi
10%/40
32.0
32.0
130.8
66.7
34.7
29.4
61.5
68.8
36.7
27.6
59.6
0.016
Selected 46 kV cases
846e0
10 mi
0.75xZL
15 mi
0
7%/50
16.0
20.0
112.1
53.1
37.1
2.9
18.9
64.7
48.7
‐8.6
7.4
0.103
846e2
10 mi
0.75xZL
15 mi
2 mi
7%/50
16.0
20.0
113.2
50.7
34.7
5.3
21.3
60.9
44.8
‐4.7
11.3
0.090
846e5
10 mi
0.75xZL
15 mi
5 mi
7%/50
16.0
20.0
114.3
48.2
32.1
7.9
24.0
56.7
40.7
‐0.4
15.6
0.074
Subtransmission cases
115‐69 kV
669f25
40 mi
0.10xZL
20 mi
25 mi
7%/60
16.0
24.0
114.0
76.0
59.8
‐10.8
5.2
79.6
63.4
‐14.2
1.8
0.032
769f25
40 mi
0.36xZL
20 mi
25 mi
7%/60
16.0
24.0
111.7
75.3
59.1
‐10.1
5.9
87.3
71.0
‐21.2
‐5.2
0.107
869f25
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
109.8
74.7
58.5
‐9.6
6.4
97.0
80.6
‐30.0
‐14.0
0.203
115‐55 kV
655e25
40 mi
0.10xZL
20 mi
25 mi
7%/50
16.0
20.0
114.5
62.1
46.0
‐5.0
11.0
64.8
48.7
‐7.5
8.5
0.024
755e25
40 mi
0.36xZL
20 mi
25 mi
7%/50
16.0
20.0
113.3
61.8
45.7
‐4.8
11.2
70.9
54.8
‐13.0
3.0
0.080
855e25
855f25
40 mi
0.75xZL
20 mi
25 mi
7%/50
16.0
20.0
112.1
61.5
45.4
‐4.5
11.5
79.1
62.9
‐20.2
‐4.2
0.157
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 26
115‐46 kV
646e25
40 mi
0.10xZL
20 mi
25 mi
7%/50
16.0
20.0
115.0
57.3
41.2
‐0.2
15.8
59.5
43.4
‐2.1
13.9
0.019
746e25
40 mi
0.36xZL
20 mi
25 mi
7%/50
16.0
20.0
114.6
57.2
41.2
‐0.1
15.9
64.9
48.8
‐6.8
9.2
0.067
846e25
40 mi
0.75xZL
20 mi
25 mi
7%/50
16.0
20.0
114.2
57.2
41.1
0.0
16.0
72.4
56.2
‐13.1
2.9
0.133
115‐34.5 kV
634d25
40 mi
0.10xZL
20 mi
25 mi
7%/40
16.0
16.0
115.3
46.2
30.2
2.6
18.7
47.7
31.7
1.4
17.4
0.013
734d25
40 mi
0.36xZL
20 mi
25 mi
7%/40
16.0
16.0
115.4
46.3
30.2
2.6
18.6
51.5
35.5
‐1.9
14.1
0.045
834d25
40 mi
0.75xZL
20 mi
25 mi
7%/40
16.0
16.0
115.5
46.3
30.2
2.6
18.6
57.1
41.0
‐6.4
9.6
0.094
138‐69 kV
869f25‐138
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
112.0
66.5
50.4
‐1.8
14.2
84.0
67.9
‐18.3
‐2.3
0.156
869f25‐138'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
131.9
71.1
55.0
‐6.3
9.8
92.0
75.8
‐25.6
‐9.6
0.158
138‐55 kV
855e25‐138
40 mi
0.75xZL
20 mi
25 mi
7%/50
16.0
20.0
113.5
55.1
39.0
1.5
17.5
68.4
52.3
‐10.8
5.2
0.117
855e25‐138'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
20.0
134.0
58.5
42.4
‐1.7
14.3
74.4
58.3
‐16.2
‐0.2
0.119
161‐69 kV
869f25‐161
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
113.2
60.7
44.7
3.7
19.7
74.8
58.8
‐9.8
6.2
0.125
869f25‐161'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
153.0
68.0
52.0
‐3.3
12.7
87.3
71.2
‐21.4
‐5.4
0.126
161‐55 kV
855e25‐161
40 mi
0.75xZL
20 mi
25 mi
7%/50
16.0
20.0
114.1
50.7
34.7
5.6
21.6
61.1
45.1
‐4.2
11.8
0.091
855e25‐161'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
20.0
154.8
56.0
40.0
0.6
16.6
70.3
54.3
‐12.6
3.4
0.092
230‐69 kV
869f25‐230
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
116.3
51.3
35.3
12.8
28.8
59.4
43.3
5.0
21.0
0.070
869f25‐230'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
24.0
217.7
61.2
45.2
3.2
19.2
76.5
60.4
‐11.4
4.7
0.070
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 27
230‐55 kV
855e25‐230
40 mi
0.75xZL
20 mi
25 mi
7%/50
16.0
20.0
116.1
43.8
27.8
12.3
28.3
49.5
33.5
6.7
22.8
0.049
855e25‐230'
40 mi
0.75xZL
20 mi
25 mi
7%/60
16.0
20.0
218.7
50.8
34.8
5.6
21.6
61.7
45.7
‐4.7
11.3
0.050
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 28
E-mail completed form to:
[email protected]
Standards Authorization Request
Form
Title of Proposed Standard
definition
NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System
Request Date
December 2, 2011
SAR Type
SAR Requester Information
(Check all that apply)
Name: Project 2010-17 Definition of Bulk Electric
System (BES) SDT
Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT Chair
Telephone: (813) 207-7994
Fax: (813) 289-5646
E-mail: [email protected]
New Standard
X
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?)
This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Purpose or Goal (How does this request propose to address the problem described above?)
Research possible revisions to the definition of BES (Phase 2) to address the issues identified through
Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition encompasses all
Elements necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
Standards Authorization Request
SAR Information
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and
technically sound definition of the Bulk Electric System (BES).
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?)
Revise the BES definition to identify the appropriate electrical components necessary for the reliable
operation of the interconnected transmission network.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Collect and analyze information needed to support revisions to the definition of Bulk Electric System
(BES) developed in Phase 1 of this project to provide a technically justifiable definition that identifies
the appropriate electrical components necessary for the reliable operation of the interconnected
transmission network. The definition development may include other improvements to the definition
as deemed appropriate by the drafting team, with the consensus of stakeholders, consistent with
establishing a high quality and technically sound definition of the BES.
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.)
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.
•
•
•
•
Form
Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources necessary for the reliable operation of the Bulk Electric System (BES)
The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous
BES - Determine if there is a need to change this position
Determine if there is a technical justification to revise the current 100 kV bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
2
Standards Authorization Request
SAR Information
network under certain conditions and if so, what the maximum allowable flow and duration
should be
Provide improved clarity to the following:
•
•
•
The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources
•
The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution
Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the BES.
Based on the potential revisions to the definition of the BES and an analysis of the application of, and
the results from, the exception process, the drafting team will review and if necessary propose
revisions to the ‘Technical Principles’ associated with the Rules of Procedure Exception Process to
ensure consistency in the application of the definition and the exception process.
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
This section is not applicable as the SAR is for a definition which is about Elements, Applicability of
entities is covered in Section 4 of each Reliability Standard.
Form
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.
3
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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.
Administers the transmission tariff and provides transmission
Transmission
services under applicable transmission service agreements (e.g., the
Service Provider
pro forma tariff).
Form
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
4
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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 box for all that apply.)
X
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.
X
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.
X
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.
X
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
X
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
X
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
X
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
X
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Form
5
Standards Authorization Request
Applicable Reliability Principles (Check box for all that apply.)
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Form
Explanation
6
Standards Authorization Request
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Form
7
Unofficial Comment Form
Project 2010-17 Definition of Bulk Electric System – Phase 2
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 September 4, 2013.
If you have questions please contact Ed Dobrowolski at [email protected] or by telephone at 609‐
947‐3673.
Project Page
Background Information - Project 2010-17 – Definition of the BES (Phase 2)
The SDT has been working on addressing the issues and directives for Project 2010‐17 Definition of the BES – Phase
2. The latest output of this work is shown below and in the second posting of the Phase 2 roadmap document. In
this second posting, the SDT is responding to industry comments raised in the first posting and initial ballot period.
The SDT has made several changes to the definition:
Inclusion I2: Dispersed power producing resources have been taken out of Inclusion I2 and returned to its own
separate inclusion (I4). This was done due to confusion on how to address the generator terminal issue for
dispersed power producing resources.
Inclusion I4: The SDT has moved dispersed power producing resources back to its own separate inclusion as
explained above. In addition, the SDT made a change to accommodate industry concerns on the inclusion of
‘collector systems’ to address the true reliability concern for loss of 75 MVA aggregated generation.
Exclusion E1:
o Exclusion E1b ‐ With the re‐institution of Inclusion I4, that inclusion needed to be added to the list in
E1.
o Note 2 has been changed from 30 kV to 50 kV per the recommendation in the supporting white paper
on sub‐100 kV looping analysis which is posted for industry consumption.
Note ‐ The SDT wishes to clarify and emphasize that the looping facilities that operate at voltages below 100 kV
are NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with
NERC’s interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric
system, unless determined otherwise in the exception process.” This was reaffirmed by the Commission in Order
773A, paragraph 36: “Moreover, as noted in the Final Rule, the sub‐100 kV elements comprising radial systems and
local networks will not be included in the bulk electric system, unless determined otherwise in the exception
process.” The sub‐100 kV looping facilities are only determinative of whether the above 100 kV elements are
evaluated for potential exclusion under the criteria set forth in Exclusions E1 or E3. If the less than 100 kV looping
facilities include a Normally Open (N.O.) device, then Note 2 does not apply – Note 1 is applicable in that instance.
Exclusion E3:
o Exclusion E3a ‐ With the re‐institution of Inclusion I4, that inclusion needed to be added to the
list in E3a.
o
Exclusion E3b ‐ ‘Real’ has been added to clarify the SDT’s intent
Exclusion E4: Pluralized the customer term.
Question 1 deals with the changes made to Inclusions I2 and I4. A diagram is provided here for reference on how
one particular configuration would be interpreted by the SDT under these revisions. As part of the review of these
changes, the SDT wishes to remind the industry that the approved Phase 1 definition included the individual
dispersed power producing resources in situations where they aggregated to 75 MVA prior to connecting to the
BES. Nothing introduced in Phase 2 has changed this approved condition.
I2 – Generating resource(s) including the generator terminals through the high‐side of the step‐up transformer(s)
connected at a voltage of 100 kV or above with:
I4 ‐ Dispersed power producing resources consisting of:
a) Individual resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to
greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.
Unofficial Comment Form
Project 2010‐17 Definition of Bulk Electric System – Phase 2 (Second Draft)
2
Question 2 deals with the change from 30 kV to 50 kV in Exclusion E1, Note 2.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or less, between configurations
being considered as radial systems, does not affect this exclusion.
The SDT has proposed an equal and effective alternative to the issue of sub‐100 kV loop analysis with respect to
Exclusion E1. The SDT has proposed a threshold of 50 kV or less for loops between radial systems when considering
the application of Exclusion E1. The SDT used a two step approach to determine the voltage level. As a first step,
regional voltage levels that are monitored on major interfaces, paths, and monitored elements to ensure the
reliable operation of the interconnected transmission system were examined to determine the lowest monitored
voltage level. Next, power system analyses determined the maximum amount of power that can be transferred
through the low voltage systems, when looped, under a worst case scenario at various voltage levels. A formal
white paper has been prepared to support this approach and is included with this posting.
Note ‐ The SDT wishes to clarify and emphasize that the looping facilities that operate at voltages below 100 kV are
NOT included in the BES. Order 773, paragraph 155 states: “Thus, the Commission, while disagreeing with NERC’s
interpretation, does not propose to include the below 100 kV elements in figure 3 in the bulk electric system, unless
determined otherwise in the exception process.” This was reaffirmed by the Commission in Order 773A, paragraph
36: “Moreover, as noted in the Final Rule, the sub‐100 kV elements comprising radial systems and local networks
will not be included in the bulk electric system, unless determined otherwise in the exception process.” The sub‐
100 kV looping facilities are only determinative of whether the above 100 kV elements are evaluated for potential
exclusion under the criteria set forth in Exclusions E1 or E3.
Question 3 deals with the clarification to Exclusion E3b on Real Power.
E3b ‐ Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery
through the LN; and
Question 4 is a generic question added to accommodate any other industry concerns with the proposed Phase 2
definition.
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and special
formatting will not be retained.
Questions
The SDT has asked one specific question for each specific aspect of the definition.
1. The SDT has separated Inclusion I2 and I4 to provide the clarity requested by the industry in the first posting
comments. In addition, again in response to industry comments, the SDT has added language to Inclusion I4b
to identify the equipment from an aggregation point of greater than 75 MVA to the connection to the BES. Do
you agree with these changes? If not, please provide technical rationale for your disagreement along with
suggested language changes.
Unofficial Comment Form
Project 2010‐17 Definition of Bulk Electric System – Phase 2 (Second Draft)
3
Yes:
No:
Comments:
2. The SDT has proposed an equally effective and efficient alternative to the Commission’s sub‐100 kV loop
concerns for radial systems by the addition of Note 2 in Exclusion E1 with a threshold value of 50 kV, and
posted a technical rationale to support this threshold. Do you agree with this threshold? If you do not support
this threshold, please provide specific suggestions and technical rationale in your comments.
Yes:
No:
Comments:
3. The SDT has added the term ‘Real’ to Exclusion E3b to clarify its intent. Do you agree with this change? If you
do not support this change, please provide specific suggestions and technical rationale in your comments.
Yes:
No:
Comments:
4. Are there any other concerns with this definition that haven’t been covered in previous questions and
comments?
Yes:
No:
Comments:
Unofficial Comment Form
Project 2010‐17 Definition of Bulk Electric System – Phase 2 (Second Draft)
4
Notice of Request to Waive the Standard
Process
Project 2010-17 Definition of Bulk Electric System
As required by Section 16 of the NERC Standard Processes Manual (SPM), this is official notice to
stakeholders that the leadership of the Definition of Bulk Electric System Standards Drafting Team and
NERC Standards Staff (Requesters) are requesting that the Standards Committee consider a waiver of the
Standard Processes Manual. The Requesters ask to shorten the next formal comment and ballot period,
and any subsequent comment formal comment and ballot periods prior to final ballot, from 45 days to
30 days in order to meet a regulatory deadline. Pursuant to Section 16 of the SPM, the Standards
Committee may reduce the duration of formal comment periods for good cause shown and to meet a
regulatory deadline.
The Standards Committee will meet via teleconference to consider this waiver request no earlier than
Thursday, August 1, 2013 (to comply with the five business day notice required by Section 16 of the
SPM). The Standards Committee’s teleconference will be noticed through an announcement and posted
on the NERC website. Additional details about the waiver request are included below, and should a
waiver be granted by the Standards Committee, it will be posted on the project page.
Justification for Current Waiver Request
NERC is required to file with FERC no later than December 31, 2013 a revised definition of Bulk Electric
System that addresses FERC directives from Orders No. 773 and 773-A.1 The basis cited in the order for
this deadline is the Standard Drafting Team’s approved project schedule, which planned for additional
comment periods being 30 days duration with the ballot occurring during the last 10 days.
An initial ballot of the revised definition ended on July 12, 2013 and achieved approximately 50%
approval. Given the time necessary to address significant volumes of stakeholder comments, the
Team’s ability to adequately consider comments and develop revisions to reach stakeholder
consensus through possibly multiple successive ballots will be significantly limited if the schedule is
not revised to accommodate 30-day postings. Thus, without the requested waiver, there is a high
degree of risk that NERC will not meet the regulatory deadline.
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.
1
Order Granting Extension of Time, 143 FERC ¶ 61,231 at P. 16
For more information or assistance, please contact Laura Hussey,
Director of Standards Development, 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 2010-17 – Definition of Bulk Electric System
2
Standards Announcement
Project 2010-17 Definition of the Bulk Electric System
Phase 2
An Additional Ballot is open through September 4, 2013
Now Available
An additional ballot for Phase 2 of the Definition of the Bulk Electric System (DBES) is open through 8
p.m. Eastern on Wednesday, September 4, 2013.
Background information for this project can be found on the project page.
Instructions
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual,
which requires all negative votes to have an associated comment submitted (or an indication of
support of another entity’s comments). Please see NERC’s announcement regarding the balloting
software updates and the guidance document, which explains how to cast your ballot and note if
you’ve made a comment in the online comment form or support another entity’s comment.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will
consider all comments received during the formal comment period and, if needed, make revisions
to the definition. If the comments do not show the need for significant revisions, the definition 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
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Individual or group. (65 Responses)
Name (45 Responses)
Organization (45 Responses)
Group Name (20 Responses)
Lead Contact (20 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 (65 Responses)
Question 1 (57 Responses)
Question 1 Comments (60 Responses)
Question 2 (48 Responses)
Question 2 Comments (60 Responses)
Question 3 (47 Responses)
Question 3 Comments (60 Responses)
Question 4 (49 Responses)
Question 4 Comments (60 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Yes
Yes
Yes
Yes
Suggest the following rewording of the Effective Dates section of the Implementation Plan to
add clarity regarding approvals: In those jurisdictions where no regulatory approval is
required the definition shall become effective on the first day of the second calendar quarter
after Board of Trustees adoption, or as otherwise made effective pursuant to the laws of
applicable governmental authorities. In those jurisdictions where no regulatory approval is
required the definition shall (go should be deleted) become effective on the first day of the
second calendar quarter after Board of Trustees adoption. NPCC participating members
suggest that when addressing the requirements pertaining to load reliability and continuity in
a standard, they must include that for a non-U.S. Registered Entity it should be implemented
in a manner that is consistent with, or under the direction of, the applicable governmental
authority or its agency in the non-U.S. jurisdiction.
Individual
Thomas Breene
Wisconsin Public Service Corporation
No
We agree with including the Generating stations with dispersed generation from the point of
aggregation to 75 MVA as I4-b does. We agree with the statement made on the BES Phase II
webinar of August 21 that this is the point where the dispersed power plant is significant to
the reliability of the BES. We disagree with including the individual resources themselves
since, as indicated on the webinar, they are not significant to the reliability of the BES .
Including dispersed power producing resources less than 25MVA ignores differences in
engineering design and operating philosophies. For our company each 2MVA wind turbine is
designed to sync on and off the grid several times a day. For this reason, the engineering
design incorporates a large contactor to handle these operations. This contactor is controlled
by the turbine PLC which contains the main protective relay functions (i.e. frequency,
over/under voltage, imbalance…etc) traditionally contained in discrete protective relays. A
generator breaker is designed in series with the contactor, which includes a self contained
overcurrent element that serves as a backup function, but is different in traditional design in
that each Protection Component is contained in the breaker device. Due to the PLC
control/protection integration, equipment differences, and operating philosophies
implementation of NERC Reliability Standards such as PRC-004, PRC-005 and FAC-008 would
be impractical and onerous lending little to no reliability improvement. We suggest
eliminating I4a completely since, as indicated on the webinar I4b encompasses the portion of
the dispersed power generating plant that is significant to the reliability of the BES
Yes
We agree with the 50kv limit since the SDT has posted a reasonable technical rationale.
Yes
No
Individual
Joseph DePoorter
Madison Gas and Electric Company
No
MG&E is voting against the BES Phase II definition due to the fact that it contains Inclusion
(I)4a; Individual resources that aggregate to a total capacity greater than 75 MVA (gross
nameplate rating). MG&E recommends that I4a be removed and I4b be maintained as the
point of aggregation is what is modeled and makes the most sense. Recommend I4 to read
as: “Dispersed power producing resources consisting of the system designed primarily for
delivering capacity from the point where those resources aggregate to greater than 75 MVA
to a common point of connection at a voltage of 100 kV or above”. Please see the following
reasons for our negative vote: 1. An individual 1.5 mW wind turbine does not impact the BES
when it reduces its output (remember just because a turbine is rated at 1.5mW doesn't mean
it automatically reaches that output when the wind blows) or trips offline. Entities have been
making comments that the place where power is aggregated (usually the bus) should be
included and not individual wind turbines, solar collectors, manure digesters, etc (as shown
in the comment form). The amount of compliance time for PRC-004 would never be
completed. Wind turbines have up to 250 plus reasons why they can trip. Usually due to the
change in wind direction. If the wind changes direction and the turbine head cannot keep up
within a certain degree of angle, the unit will trip. Coming back on line when the angle
requirements are met. So, Entity's will need to apply the R2 of PRC-004-2a, for every wind
turbine trip. We do not have the resources to review these trips and that 1.5 wind turbine
does not impact the BES. We will agree that the point of interconnection (of greater than 75
MVA) is important and should be contained in the BES definition as written in I4B. PRC-0042a is only one Standard, notwithstanding; BAL-001-TRE-01, FAC-001, FAC-003, FAC-008-3,
MOD-024, MOD-025, MOD-026, MOD-027, PRC-005, PRC-006-SPP-01, PRC-019, PRC-024,
PRC-025, and TOP-003. A 75 MVA wind farm is not equal to a 75 MVA combustion turbine.
Yes, energy flow is modeled the same (at full name plate output) but these two extremely
different facilities are quite different. The wind facility is not dispatchable (only reduction in
Mw output can take place when there is an output) and wind facilities usually are set at a
constant power factor and do not adjust for frequency deviations. 2. The SDT has
recommended that a SAR be submitted in order to refine the Standards that would be
applicable to individual power producing resources contained under I4 of the phase II
definition. This response is not acceptable. The SDT should not passively answer an entity's
question by stating that a different process "may" fix the issue at hand. Recommend I4a be
deleted and I4b be maintained as I4a. During the 8/21/2013 webinar the presenter
emphasized the critical nature of the aggregate generation of dispersed power producing
resources to the reliability of the interconnected transmission system. I4 subpart (a) is
inconsistent with the stated critical nature of the aggregate generation. The presenter also
indicated that standards that apply to GO/GOP associated standards should be addressed via
a SAR to correct reliability standards that impose a burden on the industry without providing
a significant benefit to reliability. The appropriate manner to address this discrepancy is not
to submit a SAR to modify the standards that would inappropriately invoke requirements on
individual generators due to their inclusion in the BES definition, but to eliminate I4 subpart
(a) and modify standards in the future to address any reliability issues that may need the
imposition of requirements for individual dispersed power producing resources. Please Note
that FAC-001 and FAC-002 have established processes for generators (of all shapes and sizes)
to interconnect to the BES. 3. I4a should be deleted in its entirety. The SDT is forcing every
dispersed power Facility over 75 MVA to be in the definition, where the SDT should be
keeping individual resources out and allow other Standards and SDTs to determine if that
should be included within each individual Standard. The BES definition should be written to
give broad details and each individual Standard should be where details are maintained. This
is already the case for the following Standards; MOD-025-1, R1 and VAR-001-2, R3 are two
examples where the Standard dictates what is applicable and what is not. 4. We do not
believe that since FERC has approved Phase I that the SDT is bound by that approval as being
unchangeable. The Commission has only approved a part of the process and nowhere is it
stated that once Phase I is approved that it cannot be changed. This is proof with the other
changes that the SDT has made in Phase II compared to Phase I. 5. NERC or the SDT have not
provided the industry with event analysis or lessons learned information that an individual
dispersed power producing resource (not whole facilities) within a Facility has led to
instability of the BES. 6. The inclusion of I4a does not alien itself with the current NERC and
Regional RAI process. NERC's CEO and President has said that everything cannot be a priority.
The amount of records management will only benefit a company who sells their services in
managing individual power producing resources (i.e. paper work). The Registered entity and
their Region will not see the benefit of tracking several thousand wind turbines and solar
panels, for what? The "what" is unknown because the SDT is taking words of the "Statement
of Compliance Registry Criteria" and applying it to our standards development process.
Currently Entities do not register per Facility, but this definition does force entities to register
per Facility. The SDT is mixing apples and oranges. 7. The BES SDT has stated that the
collector system is not included within the definition. But, FAC-008-3, is written to support
the reliability of the BES and Requirement 2 states that each Generator Owner shall have a
documented methodology between the generator (R1) to the point of interconnection. This
means that the collector system is part of the BES definition. Please clarify how one standard
pulls in the collector system and the proposed definition keeps it out? The removal of I4a will
solve this issue. If individual resources need to be in based on system instability issues, then
this can be addressed at a later date, once it is proven that individual resources need to be
considered part of the BES and the individual resources cause BES instability..
Yes
Yes
Yes
The inclusion of I4a does not support the reliabile operation of the BES. As stated before, we
agree that the point of interconnection should be included, not the individual intermitent
resources.
Group
Oklahoma Municipal Power Authority
Ashley Stringer
Agree
Transmission Access Policy Study (TAPS) Group
Group
Southwest Power Pool Regional Entity
Emily Pennel
No
Separation of I2, no issue No: 75MVA threshold may be higher than what FERC will support.
Comments: Paragraph 167 of Order 773 implies that FERC sees the aggregation point for tie
lines at 20MVA. However, there was some flexibility provided in the rehearing comments on
this point. Paragraph 113 of Order 773 states that multiple step-up transformers (in
particular 34.5/115kV) are expected to be included by FERC.
Yes
The technical justification document supports this conclusion.
Yes
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
This change returns it to the original language in Phase I. Either way it still has the same
intent.
No
Note two was added in draft 1 to Phase II. This change to Note 2 changes it from 30KV to
50KV, due to analysis they performed. 50KV threshold is less restrictive than 30KV. FERC
forced Note 2 – this note requires determining loops between radial lines, and including
radials with >50 KV loops
Yes
This is in regard to local networks and this change is less restrictive.
Yes
Inclusion I5 is about reactive sources. However it only excludes E4. There is no reason why all
exclusions E1 to E4 should not apply to reactive sources. The current definition will include
reactive sources in radial system as part of BES. There is no technical reason for excluding
radial system and yet including reactive sources in radial system as part of BES
Individual
David Thorne
Pepco Holdings Inc
Yes
Yes
Yes
No
Individual
Scott Bos
Muscatine Power and Water
No
MP&W appreciates the changes SDT made to I4. However, we think that the wording of I4a
still does not adequately communication that desired treatment of small dispersed power
producing resources as an aggregate, rather than on an individual basis, when the aggregate
capacity is 75 MVA or more. To address this issue, we suggest the following wording change
to I4a, “Aggregation point of dispersed resources when they aggregate to a total capacity of
greater than 75 MVA (gross nameplate rating, and” An individual 1.5 MW wind turbine does
not impact the BES when it reduces its output (remember just because a turbine is rated at
1.5 MW doesn't mean it automatically reaches that output when the wind blows) or trips
offline. Entities have been making comments that the place where power is aggregated
(usually the bus) should be included and not individual the wind turbines, solar collectors,
manure digesters, etc. The amount of compliance time for PRC-004 would never be enough.
Wind turbines have up to 250 plus reasons why they can trip. Usually due to the change in
wind direction. If the wind changes direction and the turbine head can not keep up within a
certain degree of angle, the unit will trip. Coming back on line when the angle requirement is
met. So, Entity's will need to apply the R2 of PRC-004-2a, for every wind turbine trip. Not all
Entities have the resources to review these trips and that 1.5 MW wind turbine does not
impact the BES. MP&W beleives that the point of interconnection (of greater than 75 MVA) is
important and should be contained in the BES definition as written in I4B. PRC-004-2a is only
one Standard, notwithstanding; BAL-001-TRE-01, FAC-001, FAC-003, MOD-024, MOD-025,
MOD-026, MOD-027, PRC-005, PRC-006-SPP-01, PRC-019, PRC-024, PRC-025, and TOP-003.
Yes
Yes
Yes
The SDT has recommended that a SAR be submitted in order to refine the Standards that
would be applicable to individual power producing resources contained under I4 of the phase
II definition. This response is not acceptable. The SDT should not passively answer an entity's
question by stating that a different process "may" fix the issue at hand. MP&W recommends
I4a be deleted and I4b be maintained as I4a. I4a should be deleted in its entirety. The SDT is
forcing every dispersed power Facility over 75 MVA to be in the definition, where the SDT
should be keeping individual resources out and allow other Standards and SDTs to determine
if that should be included within each individual Standard. The BES definition should be
written to give broad details and each individual Standard should be where the details are
maintained. This is already the case for the following Standards; MOD-025-1, R1 and VAR001-2, R3 are two examples where the Standard dictates what is applicable and what is not.
MP&W does not believe that since FERC has approved Phase I that the SDT is bound by that
approval as being unchangeable. The Commission has only approved a part of the process
and no where is it stated that once Phase I is approved that it can not be changed. This is
proof with the other changes that the SDT has made in Phase II compared to Phase I. NERC or
the SDT have not provided the industry with event analysis or lessons learned information
that an individual dispersed power producing resource within a Facility has led to instability
or cascading events on the BES. The inclusion of I4a does not align itself with the current
NERC and Regional RAI process. NERC's CEO and President has even said that everything
cannot be a priority. The amount of records management will only benefit a consultant who
sells their services in managing individual power producing resources (i.e. paper work). The
Registered Entity and their Region will not see the benefit of tracking several thousand wind
turbines and solar panels, for what? The "what" is unknown because the SDT is taking words
of the "Statement of Compliance Registry Criteria" and applying it to our standards
development process. Currently Entities do not register per Facility, but this definition does
force entities to register per Facility. The SDT is mixing apples and oranges.
Individual
John Seelke
Public Service Enterprise Group
No
The proposed elimination of the “collector system” as part of the BES makes the BES noncontiguous. In Order 773, the Commission (P 113 and P 114) stated that radial collector
systems used solely to aggregate generation SHOULD be part of the BES since multiple
transformers connections did not exempt I2 generators. However, FERC did not direct NERC
to include the collector system in the BES. However, it did require that radial lines that
connect I2 generators (call “tie lines” in Order 773) should be part of the BES (P 164-P 167)
for reasons of contiguity. This BES definition proposed in Phase 2 creates an unlevel
competitive environment between I4 generators and I2 generators. Moreover, in its SAR for
Phase 2, the question of BES contiguity was supposed to be addressed. The team’s response
on this issue allows dispersed power generators to be non-contiguous from the point where
ac power is produced to where it is injected into the grid. The connections of I2 BES
generators are, however, ARE included in the BES. In the diagram shown in the comment
form, if the dispersed generators were forty 2 MVA diesel generators connected as shown,
would their collector system be excluded from the BES also? What is there were eight 10
MVA gas turbines connected via a collector system? How about six 16 MVA gas turbines? As
a member of the RBB, we direct that the team include collector systems that are solely used
to aggregate generation in the BES definition.
Yes
Yes
No
Individual
Scott Berry
Indiana Municipal Power Agency
No
For question 1, Indiana Municipal Power Agency agrees with the comments submitted by
Frank Gaffney, Floriday Municipal Power Agency.
Yes
IMPA appreciates the work that the SDT has done to come up with an alternative to the
Commission’s sub-100kV loop concerns for radial systems. IMPA supports the SDT’s white
paper and the proposed 50kV threshold value.
Yes
No
Individual
Barbara Kedrowski
Wisconsin Electric Power Company
No
Wisconsin Electric appreciates the work the Standard Drafting Team (SDT) has accomplished,
but is concerned that the team has not corrected a fatal flaw in the definition of the Bulk
Electric System. During the 8/21 webinar, the SDT said that they don’t have the power to
change an existing approved definition with regard to the inclusion of individual distributed
generation resources, yet that’s what they in fact do every time they draft a standard
revision. FERC accepted the Phase 1 definition, but we believe the SDT had the opportunity
to correct the flawed definition. The SDT team did not address industry’s comments that
individual wind turbines (and other dispersed generating units) should not be included in the
definition. The SDT stated that industry has the option to address whether dispersed
generation should be applicable to a standard by revising the applicability of those standards.
This method of correcting for the wrong elements’ inclusion in the definition will take time
and resources from the industry. During this time period, the industry would still need to
assume responsibility for compliance to each affected standard because it would be
unknown when/if the revisions would be accepted and approved. For instance, compliance
to Reliability Standard PRC-005 requires the industry to include thousands of individual wind
turbines (and small solar panels) in the maintenance and testing of relays and associated
equipment. Resources required to complete this testing are specialized and significant, with
little to no measureable benefit to the BES (and an indirect detriment by taking those
resources away from other tasks that are beneficial). In regards to CIP Version 5
requirements, if each wind turbine is part of the BES, then each wind turbine’s monitoring
and control systems will be “BES Cyber Systems”. Again, resources will be required for
compliance with no benefit to reliability. Individual dispersed generation units (generally less
than 2 MW) do not impact the reliability of the Bulk Electric System. The SDT points out that
it is not including collector circuits of dispersed generators because collector circuits do not
have a true reliability impact, but the SDT fails to recognize that the individual dispersed
generators have even less of an impact. The issue of concern is a single point of failure
affecting 75 MWs of generation, not the failure of an individual wind turbine. By excluding
the collector systems, but including the individual generators, the SDT team is not following
FERC’s Order 773 (issued 12/20/2012) Paragraph 165, in which the Commission stated that it
is appropriate to have the bulk electric system contiguous, without facilities or elements
“stranded” or “cut-off” from the remainder of the bulk electric system. The individual
dispersed generating units are stranded from the remainder of the bulk electric system in the
current draft of the definition. The SDT stated during the 8/21 webinar, that industry can use
the exception process to exclude wind turbines, or other dispersed generators. This
viewpoint has a fundamental problem. It mandates that individual generators be included in
a faulty definition that pulls in insignificant elements into the BES and then requires industry
to exclude them (essentially an entire asset type). That requires hundreds of dispersed
generator owners to rely on the regulator to be reasonable and allow us to exclude all of our
individual dispersed generators. The proposed Phase 2 definition poses a huge compliance
and regulatory burden that doesn’t add to the reliability of the BES.
Individual
John Bee
Exelon and its' affiliates
Yes
Yes
Yes
Yes
Suggest adding the following to E4: or for the sole purpose of regulating internal generating
station auxiliary buses. So that it reads: E4 – Reactive Power devices installed for the sole
benefit of a retail customer(s) or for the sole purpose of regulating internal generating
station auxiliary buses.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Agree
Transmission Access Policy Study Group (TAPS) and SERC OC Review Group
Group
Salt River Project
Bob Steiger
Yes
Yes
Yes
No
Individual
Gary Kruempel, Terry Harbour, Tom Mielnik
MidAmerican Energy Company
No
The SDT has made significant progress by separating dispersed power producing resources
from traditional generating resources. By including I4 subpart (b) the SDT has identified the
critical element(s) that impact reliability. However, by failing to address the issue of reliability
standards as they apply to individual dispersed power resources, the SDT has perpetuated a
gross error implemented in phase one of the BES, by including each individual dispersed
resource as BES. During the 8/21/2013 webinar the presenter emphasized the critical nature
of the aggregate generation of dispersed power producing resources to the reliability of the
interconnected transmission system. I4 subpart (a) is inconsistent with the stated critical
nature of the aggregate generation. The presenter also indicated that standards that apply to
GO/GOP associated standards should be addressed via a SAR to correct reliability standards
that impose a burden on the industry without providing a significant benefit to reliability. The
appropriate manner to address this discrepancy is not to submit a SAR to modify the
standards that would inappropriately invoke requirements on individual generators due to
their inclusion in the BES definition, but to eliminate I4 subpart (a) and modify standards in
the future to address any reliability issues that may be required of individual dispersed
power producing resource. The following language is recommended for I4: Dispersed Power
Producing Resources: Where dispersed power producing resources aggregate to greater than
75 MVA the to a common point of connection at a voltage of 100 kV or above. Note:
Individual dispersed power producing resources are not BES, but does not exempt
registration as a GO or GOP. Dispersed power producing resources are small-scale power
generation technologies using a system designed primarily for aggregating capacity providing
an alternative to, or an enhancement of, the traditional electric power system. Examples
could include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells. Justification: A dispersed power generating facility necessarily
consists of individual units of a limited size to take advantage of the distributed nature of the
resource (e.g., wind or solar) upon which the facility relies for its fuel source. One benefit of
such facilities’ unit size and geographical distribution is that they are not as susceptible to a
substantial loss of generating capability as a single unit of 20 MVA or greater (the registration
threshold for a single generating unit). If the arrayed generators were each 2 MVA then the
probability of losing 20 MVA at the generator level would be .00000001%. If the units were 5
MVA each the probability of losing all four units at the generator level would be .01%. The
probability of losing a single 20 MVA unit would be 10%. These variations illustrate that there
will be different values depending upon the arrayed generator’s size. Given the reliability
advantage this diversity affords it does not seem reasonable to treat this type of facility in
the same way as a single unit facility of 20 MVA or greater. As recognized by the SDT and
FERC in Order No. 773, a dispersed generating facility of 75 MVA or greater (NERC Registry
Criterion Section III.c.2) can have an impact on the BES. To recognize this impact and to also
account for the dispersed nature and reliability advantage as described above, it is requested
that the individual power producing resources be excluded from the BES. A technical
example of the impact of the loss of an individual wind turbine to the BES is available to the
SDT upon request.
Yes
Yes
No
Individual
Shaun Moran, Lynn Schmidt, Joe O'Brien, Ed Mackowicz,
NIPSCO
No
We requested some clarification regarding a wind farm within NIPSCO from members of the
SDT, and promptly received feedback. The main concern is that we are not sure of the intent
of inclusion I4 because it is attempting to include a bus within an intermediate voltage. In our
case it is 69 kV that may or may not be included since there are 2 transformations within the
path to the 138KV; 1 up to 69 kV and 2 parallel transformers up to the 138 kV. In addition the
entire 69 kV path is not “designed primarily for delivering” this wind power to the 138 kV
system; the 69 kV system includes many lines serving various demand. Some on the SDT felt
that the single step-up transformer is the same as 2 transformers in parallel, while others did
not. Following this discussion we failed to receive a uniform clarification. Some opinions
were that the 69 kV system would be included in the BES while others believed it would not;
we have similar differing interpretations within NIPSCO. Further clarification needs to be
made on whether or not multiple transformations are or are not included.
Yes
We'd rather see it at 70 kV, however we appreciate the analysis that was performed
justifying the 50 kV.
Yes
good
Yes
Another major concern is whether our 138 kV industrial customers with multiple feeds are
part of the BES. One of the criteria is whether power ever flows through the customer's
system. This could be very difficult to prove with evidence. Perhaps during the last year's
peak load or maximum transfer across the host TOP's system, the flow could be integrated
over an hour; if there is system flow across the customer's system during the integrated
hour, then the customer's system should be considered part of the BES and the customer
should have multiple years to comply with becoming part of the BES. If the customer
becomes part of the BES would this mean that they would have to become a TO/TOP? Would
it require that they have NERC certified operators? We see these as emerging concerns.
Additionally, it appears that several small wind generators may become part of the BES which
would bring PRC-004 misoperations into play for them. It is our understanding that such
generators trip off line based on wind and wind direction. Keeping track of these operations
and the associated analysis may become quite an undertaking. Other standards such as PRC005 may also become a concern.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
We suggest that NERC and the SDT consider revising Note 2 to read as follows: Note 2 – The
presence of a contiguous loop, operated at a voltage level of 50 kV or less, between
configurations being considered as radial systems, does not affect this exclusion. Non-US
Registered Entities can adopt the same voltage level or should be implemented in a manner
that is consistent with, or under the direction of, the applicable governmental authority or its
agency.
Yes
No
Individual
David Jendras
Ameren
Yes
No
In our opinion, the SDT has improved the E1 exclusion criteria by increasing the 30 kV
threshold to 50 kV. However, we still believe that the threshold is too low and request that it
be raised to at least 70 kV. As the definition now stands, we will have to perform what we
feel is unnecessary analysis to prove that most of our local subtransmission networks should
also be excluded.
Yes
We agree with the addition of the word “Real”, but we have other concerns with E3b and we
have identified in the comments to question 4 below.
Yes
1. We request the SDT to provide clarification for E3b testing conditions, specifically for all
facilities in service or for single transmission contingency conditions. We believe that the
criteria needs to be very clear so it is not confusing for entities when determining inclusion of
local network facilities as BES facilities. 2. Also, we do not believe that 1 MW of back-feed
from local network facilities to transmission facilities for a few hours out of the year
constitutes classification of the local network facilities as BES facilities. We request that the
SDT consider for inclusion that the magnitude of the injections from the local network should
be in line with other injections into the transmission system such as: (a) Generators with a
nameplate greater than 20 MVA, or (b) Aggregate resources greater than 75 MVA. 3. In our
opinion, the standard puts additional burden on local network owners including local
subtransmission network owners to prove that their facilities should be excluded from
consideration as BES facilities. (a) We believe that, testing for BES inclusion could be included
in the annual TPL contingency analysis, but it may not be possible to complete this type of
analysis before the end of the year unless the criteria is clearly defined and limited in scope,
otherwise numerous models reflecting varying system conditions would need to be
considered. (b) We ask the SDT to recall that it was suggested in the last webinar that SCADA
data could be used to prove that there was no back-feed from the local network to the
transmission system. (c) We realize that the accuracy of SCADA data at low flow levels can be
suspect at low load flows but if considered with the type of relaying, that is if the relaying
limits power flow back into the BES transmission system, this could be used as a means of
quick determination for inclusion. We appreciate the work of the SDT effort to provide a
reasonable and balanced approach to the determination of BES facilities, and doing all of this
within a very short period of time. Again we ask the SDT for consideration with respect of the
50kV threshold being raised to 70kV, and that with respect to injections into the transmission
network from the various generation and local network sources that they be considered as a
comparable basis in the determination of BES facilities.
Individual
Chifong Thomas
BrightSource Energy, Inc.
No
No. We agree with the separation of I2 and I4 and this does provide clarity by creating a
distinction between more traditional generation and distributed generation resources. We
disagree with I4 to be applied only when both (A) and (B) are true. We recognize that each
single small generator or even a group of these small generators cannot impact the BES and
therefore, we would support the including only of the individual generating resources (A)
(i.e., greater than 75 MVA) in the definition. The inclusion of the aggregate point (B) below
100 kV will improve reliability by focusing on the area that can cause the loss of 75MVA of
distributed generation resources. We recognize that there will be complication in
determining the aggregate point and to the implementation of standards associated with this
portion of the collector system. For example, the various standards that are associated with
the BES definition will also need to apply to this portion of the collector system and
associated low voltage equipment.
Yes
Yes
Individual
Amber Anderson
East Kentucky Power Cooperative
No
In the consideration of comments, the drafting team indicated that a SAR might be submitted
to appropriately adjust GO and GOP standards requirements for dispersed generating
facilities. We agree that is the approach to undertake. In order to support this approach, I4
should be deleted to avoid the situation where inappropriate provisions could become
effective and compliance become difficult or impossible for entities until work is completed
through the SAR to adjust those requirements. In the filing with FERC this procedure could be
explained so that FERC can be assured that their approval of inclusion of dispersed
generating facilities in the Phase I order will be appropriately implemented.
Group
Dominion
Louis Slade
Yes
Yes
Yes
No
Individual
Thomas Foltz
American Electric Power
No
AEP does not agree with the premise that BES elements (measured for compliance) should
be as granular as the individual dispersed power resource. We do not see the reliability
benefit of tracking all of the compliance elements for individual wind turbines when the
focus should be placed on the aggregate of the facilities. Does the RC want to be notified of
an outage of each individual wind turbine in real-time, or a loss of significant portion of the
wind farm? If we are not careful, we will have entities at these resources and others
monitoring them (BAs, TOPs, RCs) focusing on minor issues that will distract from more
relevant reliability needs. We believe it would be beneficial and provide more clarity if the
verbiage “aggregate to a total capacity greater than 75 MVA (gross nameplate rating) at a
common point of connection to a voltage of 100 kV or above” were moved to the beginning
of the I4 paragraph rather than as a sub-bullet. For example, “Dispersed power producing
resources that aggregate to a total capacity greater than 75 MVA….”. We appreciated the
development of the diagram to explain the scenario. We encourage the team to continue to
provide these illustrations to clarify the intent and the application.
No
The thought process of the note #2 is confusing the process. One could take this to mean
that a 69 kV system would be included by exclusion. AEP does not believe this to be the case,
but the wording of this note does not lead to an obvious conclusion. We suggest that the SDT
make another attempt to provide a simpler and clearer approach. AEP also suggests that E1
have transmission removed from between the words contiguous and Elements. We
recommend that it instead say “Radial systems: A group of contiguous Elements that
emanates from a single point of connection of 100 kV or higher and:”
Yes
Yes
To reiterate, AEP does not agree with the premise that BES elements (measured for
compliance) should be as granular as the individual dispersed power resource. We do not see
the reliability benefit of tracking all of the compliance elements for individual wind turbines
when the focus should be placed on the aggregate of the facilities. Does the RC want to be
notified of an outage of each individual wind turbine in real-time, or a loss of significant
portion of the wind farm? If we are not careful, we will have entities at these resources and
others monitoring them (BAs, TOPs, RCs) focusing on minor issues that will distract from
more relevant reliability needs. We appreciated the development of the diagram to explain
the scenario. We encourage the team to continue to provide these illustrations to clarify the
intent and the application. When the guidance documents were produced last year, we had a
better understanding of how the pieces of the definition fit together (and where there were
significant gaps). We encourage the SDT to develop the scenarios and the diagrams first for
industry review then the definition should be crafted to meet those. We understand the
pressure to meet the FERC deadlines, but continuing to tweak this foundation little by little
had proved to be a difficult task and an overhaul of the approach might yield better results. If
this requires modifying the SAR to provide the SDT with the flexibility to address broader
concerns, AEP endorses this approach.
Individual
William Waudby
Consumers Energy Company
No
The proposed wording of I4(b) is acceptable in that includes “…from the point where
resources aggregate to greater than 75 MVA…”. Consumers Energy objects to I4(a) which
includes all “individual resources that aggregate to a total ampacity greater than 75 MVA”.
This could be interpreted to include each of the small generators, each 690V to 34.5kV
transformer and the collector systems on a wind farm. I4(a) should be removed from the BES
definition leaving only I4(b) as an inclusion. Consumers Energy recommends a negative ballot
until the wind farm generators, transformers and collector systems are excluded.
Yes
Yes
No
Individual
Kenneth A Goldsmith
Alliant Energy
No
Alliant Energy agrees with the changes to I2 and I4b, however, firmly believe I4a must be
deleted. There is no way an individual dispersed generator in the range of <1 MW to 5 MW
will have any reliability impact on the reliability of the BES. In addition, in the MRO footprint
alone there would be ~7500 generators added to the list of BES equipment, which would be
extremely costly to manage from both the Registered Entity and Regional Entity's
perspective.
Yes
Yes
Yes
Alliant Energy reiterates that Inclusion I4a must be removed from the definition of the BES. It
makes no technical sense, and creates an extremely burdensome compliance workload and
risk.
Individual
Nazra Gladu
Manitoba Hydro
Yes
Yes
Yes
Yes
(1) General Comment - replace “ Board of Trustees ” with “ Board of Trustees’ ” throughout
the applicable documents/standards for consistency with other standards.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
Yes
Yes
Yes
Yes
HQT's position remains the same concerning the BES Definition, as limitations on exclusion
are increased in phase 2 as imposed by FERC without proper hearing of non-US jurisdictions.
One other comment on the Implementation plan refers to the second sentence of Effectives
dates. The second sentence should be arranged differently as it refers both to "no regulatory
approval required" and "applicable governmental authorities". The last part of the sentence
should be moved with the first sentence to add clarity.
Individual
Kayleigh Wilkerson
Lincoln Electric System
No
Although appreciative of the drafting team’s efforts, LES is concerned with the proposed
inclusion of the individual dispersed power producing resources as part of the Bulk Electric
System versus the point at which the resources aggregate to a capacity greater than 75MVA.
As currently proposed, the burden would be on the registered entities to either seek multiple
exclusions through the BES Exception Process or else race to add numerous BES Elements to
existing programs, processes and maintenance schedules to ensure compliance with
Reliability Standards such as PRC-005-1.1b, PRC-004-2a, FAC-001, etc. To prevent broad
sweeping changes to existing compliance requirements without sufficient technical
justification, LES recommends Inclusion I4a be removed altogether and I4b be retained. In
the event a reliability-related need is identified in the future pertaining to the individual
resources, LES suggests that revisions be made to those standards deemed applicable.
Individual
Don Schmit
Nebraska Public Power District
Yes
Still have concern with including individual wind turbines as it relates to total generation.
No
The white paper for the low voltage loop threshold is a logical review of the issues. We would
like to see some clarification for certain configurations. For example, two 115kV/69kV
parallel transformers at the same substation serving only load at 69kV and no looped 69kV
lines: 1) with 115kV and 69kV bus tie breakers, 2) with no 115kV bus tie breaker but does
have a 69kV tie breaker, 3) with no 115kV bus tie breaker and no 69kV tie breaker, and 4)
with 115kV bus tie breaker and no 69kV tie breaker. All breakers are normally closed but if no
breakers exist then transformers are connected directly by bus operating in parallel for all
cases. Does this make the interrupting device on the high side of each transformer BES
elements? Does this make the transformer a BES element or suggest an analysis for an
exception must be made to remove them from the BES? Our concern is how a PRC-005
audit/enforcement group will interpret these configurations if it is not clearly stated in an
example or considered in the white paper. How would the SDT interpret a configuration
where a 115kV “radial” line feeds a substation with a 56MVA 115/69kV transformer. The
69kV side of the transformer is connected to a networked 69kV system owned by another
entity. The 69kV system does connect back to the transmission system in multiple points in
the other entities system. There is some 69kV generation greater than 20MVA or 75MVA
aggregate but the substation and line in question is not used for black start. Note the
115kV/69kV transformer would never allow greater than 75MVA to pass through it back to
the 115kV line since the transformer is too small. Is the substation with the 115/69kV
transformer a BES substation? Is the 115kV line to the 115kV/69kV substation BES? Please
clarify. It seems transformer size should have some impact but the reference document does
not reference this.
Yes
Yes
It is imperative to have the BES reference document be updated to reflect the latest changes
and drafting team position on various items with the definition since the definition is not selfexplanatory due to the significant BES system variations. Perhaps some additional examples
with low voltage looped systems would be beneficial similar to the scenarios noted in
question 2 above. We also have concerns with the disclaimer in the reference document on
page 1 and noted below. We would hope this document would be endorsed by NERC to help
address the complexity of the definition and to aid in transparency. “Disclaimer-This
document is not an official position of NERC and will not be binding on enforcement
decisions of the NERC Compliance Program. This reference document reflects the
professional opinion of the DBES SDT, given in good faith for illustrative purposes only.”
Group
seattle city light
paul haase
Agree
Sacramento Municipal Utility District (SMUD)
Individual
Larry Watt
Lakeland Electric
Agree
Lakeland Electric supports the Florida Municipal Power Agency comments.
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
Yes
(1) The definition utilizes the term “non-retail generation.” This term does not appear to be
clarified within the definition. However, the drafting team has attempted to clarify the term
in the guidance document. Unfortunately, the guidance document is not final, meaning that
it can be revised before being finalized. Please define retail and non-retail generation as
separate definitions for inclusion into the Glossary contingent upon each other or make the
BES definition approval contingent on the guidance document being approved. See Exclusion
E1(c). (2) The terms “plant and facility” are not defined and are ambiguous. Please provide
quantitative and/or qualitative factors that an entity can utilize in determining what is a
plant/facility. See Inclusion I2. (3) The following note will be placed in the Reference
document: “Dispersed power producing resources are small-scale power generation
technologies using a system designed primarily for aggregating capacity providing an
alternative to, or an enhancement of, the traditional electric power system.” Please strike
the following language from the paragraph “or an enhancement of,” as it is more of a
persuasive statement than an objective statement. (4) In Exclusion E1(c), please clarify that
reactive devices, such as capacitor banks, can be included in this section also. Reactive
devices are differentiated from real power devices in Inclusion I2 and so we request
clarification that reactive devices can be included in Exclusion E1(c). (5) Inclusion I2 includes
generation above 20 MVA/75MVA connected at 100 kV or higher. However, the base
definition includes all generation units connected at 100 kV or higher. Units below 20
MVA/75MVA are never actually excluded. The net effect is to include all generation under
the base definition regardless of size. To avoid future interpretation issues and ensure
consistency with the intent communicated in the Phase 1 guidance document (page 13,
Figure I2-6), Inclusion I2 needs to be written as an exclusion of units less than 20 MVA/75
MVA. If this not the intent of I2, then the definition needs to be modified to clarify the intent.
(6) Exclusion E2 currently states “: (i) the net capacity provided to the BES does not exceed 75
MVA, and (ii) standby, back-up, and maintenance power services…”. This statement could
easily be covered under the section currently labeled I2 and suggested above to be rewritten
as an exclusion. We would like to suggest potential language to simplify the definition,
eliminate inclusion I2 to ensure that units under 20 MVA/75 MVA are actually excluded from
the definition, and incorporate these ideas into exclusion E2 so that Exclusion E2 would be:
E2 – Generating resource(s) including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above with: a) Gross individual
nameplate rating less than 20 MVA. Or, b) Gross plant/facility aggregate nameplate rating
less than 75 MVA. Or, c) One or more generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance
power services are provided to the generating unit or multiple generating units or to the
retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a
Generator Owner or Generator Operator, or under terms approved by the applicable
regulatory authority. (7) It would be extremely valuable for the team as part of any guidance
document to develop and review a decision tree supporting the definition and include this
decision tree in the next revision of the guidance document.
Individual
Wayne Sipperly
New York Power Authority
LPPC
No
Inclusion 4b does not support a contiguous BES due to the exclusion of a portion of the path
from the generator terminals to the resource aggregation point. Inclusion 4b is not
consistent with the elements included under Inclusion I2 which applies to all generating
resources.
Yes
Yes
Yes
Support the development of a SAR that will create a project to review all of the GO and GOP
standards for effective applicability to dispersed power resources so that generator owners
and operators are only subject to the Standards requirements that have reliability impacts
and those standard requirements that are applicable to the generator type.
Group
Transmission Access Policy Study Group
William Gallagher
Yes
Although we support the SDT’s willingness to address the lack of clarity caused by the
previous posting’s merging of I4 with I2, we are concerned that the wording of the new
version of I4 does not capture the SDT’s intent, and could lead to absurd results if read
literally. As we understand it, the SDT’s intent is to include only dispersed power producing
resources that both (a) aggregate to more than 75 MVA, and (b) are connected through a
system designed primarily for delivering capacity at a common point of connection of 100 kV
or above. We believe that the SDT also intends that only the individual resources and the
point from which they aggregate to 75 MVA should be included in the BES; in other words,
the portion of the collector system that carries <75 MVA is not BES by virtue of I4. In order to
express that intent clearly, we suggest the following revised text: I4 - Dispersed power
producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate
rating), and that are connected through a system designed primarily for delivering such
capacity from the point at which those resources aggregate to greater than 75 MVA to a
common point of connection at a voltage of 100 kV or above. The BES portion of such
resources includes: a) The individual resources, and b) The system designed primarily for
delivering capacity from the point where those resources aggregate to greater than 75 MVA
to a common point of connection at a voltage of 100 kV or above. We believe that this text is
consistent with the intent reflected in the diagram provided by the SDT in the comment
form, and is more clear and accurate than the text of I4 as posted.
Yes
TAPS appreciates the SDT’s work on the sub-100 kV loop issue. For the reasons set out in the
SDT’s white paper, and in TAPS’ comments on the 30 kV threshold that was proposed in the
first posting of Phase 2 of the BES definition project, TAPS strongly supports the proposed 50
kV threshold.
Yes
We suggest that the SDT clarify, either in the definition itself or in the reference document,
that a momentary flow-through caused by an abnormal/contingency condition does not
make a system ineligible for Exclusion E3. TAPS members are willing to work with the SDT on
defining appropriate limits for such minimal, momentary flow-throughs.
Group
Southern Company
Wayne Johnson
Yes
The separation of dispersed generation where a collector system aggregates the total
generation prior to connecting to the BES is clear in I4.
Yes
It is clear that looping facilities operating at voltages < 100 kV are NOT included in the BES
and that contiguous loops operated at voltage < 50 kV in configurations being considered as
radial systems does not affect this exclusion (i.e., they are also NOT included in the BES).
Yes
Yes
A) Inclusion I2a should be deleted and I2b should be used to define the threshold for all
generating facilities. It is inconsistent to include a 21 MVA single generator (using I2a) and
not include 74.5 MVA aggregated conglomeration of individual generators (using I2b). Since
75 MVA is used as the threshold in multiple places in this definition, a single generator at 75
connected at > 100kV should be the individual unit size threshold. B) Please specify what size
of Reactive Power resources is included by I5. Order 773 acknowledged that Inclusion I5 is
the technical equivalent of Inclusion I2 (generating resources) for reactive power devices.
Since generating resources in Inclusion I2 are limited to those connected at 100kV or above
with individual and aggregate ratings of 20MVA and 75 MVA, respectively, it could be
consistent -- if technically justified -- to include a threshold of >75MVAR for reactive power
resources. Some technical justification should be pursued to determine whether 75 MVAR or
a different size threshold would be appropriate to include in Inclusion I5 for Reactive Power
resources. C) Southern Transmission believes that Exclusion E3 should include a limit on the
size of a Local Network (LN). This position is consistent with the proposal from the NERC
System Analysis and Modeling Subcommittee (SAMS). Without placing a size limitation on
such a network, a single contingency could result in significant flows across the BES to serve
the LN from a different location. The SAMS provided technical justification for a 300 MW load
limit and Southern would be supportive of such a limit. Southern also agrees with the SAMS
that the flow should be into the LN under single contingency conditions. (See NERC’s Review
of Bulk Electric System Definition Thresholds, March 2013, Section 5.3) D) Southern believes
that the second part of Exclusion E3 should be deleted for three reasons: First, Exclusion E3a
refers to “non-retail generation”. Southern believes that whether a unit is “retail” or “nonretail” should be irrelevant when determining inclusion in the BES. Regardless of how a
generator is classified, if it is large enough to impact flows on the system, then it should be
included in the BES. Second, the phrase “and do not have” in the second phrase of Exclusion
E3a is ambiguous and redundant and could lead to confusion and misapplication. Specifically,
it is ambiguous as to whether the last phrase regarding aggregate non-retail capacity: (a)
refers back to the generation resources identified in Inclusion I2, I3, or I4 (thus defining a
smaller subset of generation resources from I2, I3, and I4 that are carved out from the
definition of LN, but other Inclusion I2-I4 generation resources can be part of the local
network); or (b) simply refers back to “generation resources” (therefore, local networks
exclude BOTH Inclusion I2-I4 generation resources AND, separately, generation resources
with aggregate non-retail generation >75MVA). Third, Inclusions I2 and I4 already both use
the 75 MVA limit. It seems redundant to state that a Local Network under Exclusion E3a does
not include generation resources with aggregate capacities greater than 75 MVA when
Exclusion E3a already states that local networks do not include generation resources
identified in Inclusion I2 and I4 (which, in turn, include generation resources with aggregate
capacities above 75 MVA). To clarify and to eliminate confusing and unnecessary
redundancy, Southern suggests striking all language after “Inclusion I4.” Exclusion E3a should
therefore read: “a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusions I2, I3, or I4.”
Individual
Mahmood Safi
Omaha Public Power District
No
Omaha Public Power District (OPPD) agrees and appreciates the SDT’s efforts to provide
clarity by separating dispersed power producing resources from Inclusion I2 and returned to
its own separate Inclusion I4. However, OPPD is still concerned with the Inclusion I4a that
includes the individual generator as part of BES. Where, the Inclusion I4b clearly and
correctly recognizes the aggregate point to be identified as a BES facility. We agree that the
aggregation point (or bus) should be part of the BES, if the total aggregated generation is at
75 MVA or higher, as stated in the Inclusion I4b. OPPD believes that the individual unit by
itself can’t impact the reliability of BES. On the other hand, the compliance responsibilities
that go along with are burdensome with no benefit to the reliability of the BES. Therefore,
OPPD suggests consider removing Inclusion I4a from the BES Definition Inclusions. We
strongly believe that I4b is completely addressing the dispersed power producing resources
inclusion into BES. Additionally, OPPD supports comments provided by Madison Gas &
Electric (MG&E).
Yes
Yes
No
Individual
Don Streebel
Idaho Power Company
Yes
Yes
Yes
Yes
1. In the wording for E3b (Local Networks), the phrase “and the LN does not transfer energy
originating outside the LN for delivery through the LN” does not seem to add any value or
specificity to the LN Exclusion. In fact, the phrase seems misleading and serves to add
confusion since some amount of energy flowing in a parallel BES path outside the LN will
always flow through the LN, even if it’s just a trickle and does not impact the sign of the
measured power flow at the LN points of connection. Suggested reword for E3b is “Real
power flows only into the LN at each LN connection point.” 2. We agree that your clarifying
single-line diagram for Inclusion I4 (40 - 2 MVA generators aggregated up through the point
of aggregation to the common point of connection) for dispersed power producing resources
properly designates the point of aggregation of the dispersed power producing resources as
a BES element. We also agree with the basis for this designation which states for the point of
aggregation "where the individual generator nameplate ratings of the dispersed generation
total > 75 MVA (actual 80 MVA) and a single point failure would result in loss of all
generation contained on the dispersed generation site". However, following the same logic in
basis, we do not agree with the BES designation for each individual 2 MVA generator in your
clarifying single-line diagram. We think it makes sense that the reliability of the power
system should be considered for the loss of the 80 MVA and we agree that a potential single
point of failure exists at the point of aggregation that could result in the loss of all
generation. However, we do not think that the loss of one 2 MVA generator would have any
significant negative impact on the reliability of the power system. If the loss of greater than
20 MVA via a single point failure scenario is deemed significant to the reliability of the power
system (Inclusion I2, a), then that same logic suggests that each of the two buses that
aggregates 40 MVA of generation should be designated as BES. If, on the other hand, due to
the dispersed nature of the generation in the clarifying single-line diagram, the loss of
greater than 75 MVA via a single point failure scenario is deemed significant to the reliability
of the power system (Inclusion I2, b), then that same logic suggests that the point of
aggregation that aggregates 80 MVA of generation should be designated as BES. No place in
the BES core definition nor in any of the inclusions (or exclusions) is there a concern for the
loss of 2 MVA of generation as having a negative reliability impact on the power system.
Therefore, we would not designate each individual 2 MVA generator as BES as you have in
your clarifying single-line diagram and would suggest the following wording for Inclusion I2
for your consideration: I2 - Generating resource(s) with: a) gross individual nameplate rating
greater than 20 MVA, including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above or, b) the point of aggregation of
gross plant/facility with aggregate nameplate rating greater than 75 MVA, including the
system designed primarily for delivering the aggregated capacity from the point where the
resources aggregate to greater than 75 MVA to a common point of connection at a voltage of
100 kV or above. I4 - DELETED
Individual
Diane Barney
NARUC
Yes
NARUC shares the concern raised by New York about the Phase II Report’s failure to meet its
purported goal of providing a technical justification for 100kV bright line rule and generation
thresholds. NY raised specific concerns about a survey not being appropriate technical
support for specific numbers and the drafting team did not specifically address this, or other
concerns raised about the technical justification, in its response. NARUC is also concerned
that the methodology utilized historically by the NPCC was not considered as one of five
alternatives. So in response to whether or not there are other concerns with this definition
that have not been covered in previous questions and comments, NARUC notes that it shares
these concerns that have been raised, as well as the lack of a response from the drafting
team thus far and requests a thorough response.
Individual
Thomas Dvorsky
New York State Department of Public Service
Yes
NERC has an obligation to provide technical advice to FERC, so that any number provided to
FERC by NERC is interpreted as technical advice. A major purpose of the BES Phase II effort
was to establish a technical basis for the 100 kV brightline and the 20/75 MVA generation
levels. While NERC has provided a report purportedly providing a technical basis for these
threshold levels, the report fails to do so. NERC should not include any numbers in any
definition or standard for which it cannot provide a technical basis. Surveys do not provide a
technical basis. Particularly troublesome is the presentation of alternatives to the 100 kV
brightline. The report authors looked at 5 alternatives to establishing a technical basis for
determining the bulk system. The report failed to evaluate the methodology historically
applied to the NPCC system. If a major NERC region was able to successfully apply their
methodology, why was it not evaluated and why would it be impossible to expect other
regions to perform a similar analysis as the base for determining the BES? This comment is
being resubmitted as the response provided in the previous comment period does not
address the issues raised.
Group
NAGF Standards Review Team
Patrick Brown
No
1. Replace the current ballot’s draft I4 language: “I4 - Dispersed power producing resources
consisting of: a) Individual resources that aggregate to a total capacity greater than 75 MVA
(gross nameplate rating), and b) The system designed primarily for delivering capacity from
the point where those resources aggregate to greater than 75 MVA to a common point of
connection at a voltage of 100 kV or above.” With the proposed comment I4 language: “I4 Dispersed power producing resource projects, or portion(s) thereof, designed primarily for
supplying wholesale power (e.g., a wind farm, or solar farm) that aggregate to a total
capacity greater than 75 MVA (gross nameplate rating) at a common point of connection to a
voltage of 100 kV or above consisting of: a) The individual resources, and b) The delivery
system designed primarily for delivering capacity from i) the point where those resources
aggregate to the total connected capacity; to ii) a common point of connection at a voltage
of 100 kV or above.” Rationale: • “projects … designed primarily for wholesale” – nothing in
this posted version distinguishes between generation for retail (behind the meter) and
generation for wholesale. As such rooftop PVs, generator assistance programs, or other
similar small power-producing incentives, might be otherwise interpreted as included under
I4. • “(e.g., a wind farm, or solar farm)” – Because the SDT’s I4 text-box will be dropped from
the final version, we believe this inclusion is necessary to retain an illustration of the intent. •
I4.a - While imposing BES Standards of governance toward management of individual small
units is counter-productive and administratively burdensome, we do agree that
differentiating applicability to various Standards should be specified through those
Standards. To that end, we are dedicated to drafting and vigorously promoting a SAR to
appropriately address dispersed power producing resource applicability within individual
NERC Standards. In keeping with that commitment it is suggested that I4a be deleted from
the BES definition. This would avoid temporarily imposing inappropriate requirements that
would later have to be eliminated by modification of individual standard requirements. A
better approach would be to add requirements where needed for individual small units. •
I4.b – We believe our proposed wording: o Appropriately addresses impact to BES reliability.
Rather than offering some illusion for reliability at a lesser impact level, this proposal
recognizes that reliability rests in TPs, BAs, RCs, and TOPs responsibly addressing the single
greatest contingency arising from, and the behavior of, dispersed power producing resources
in the aggregate. Enforcing governance for management to any lesser level is not productive
and has no true value to BES reliability. o Better aligns with FERC’s Determination within
Order 770 paragraph 114. o Aligns with FERC’s Determination for I2 within Order 773
paragraph 91. o Aligns with FERC’s Determination for I2 within Order 773 paragraph 92.
Yes
1. The language of the proposed BES definition is rather convoluted and is therefore difficult
to apply correctly without the Reference Document. The FERC order 773/773a-amended
Reference Document is not complete or final for the phase-2 BES definition, however. Its
exclusion E1 statement is that of phase-1, not phase-2, for example, and a disclaimer on p.1
states “…this reference document is outdated. Revisions to the document will be developed
at a later date to conform to the definition being developed in Phase 2.” It appears that the
phase-2 BES definition is being rushed through the approval process, and it would be
preferable to take the time to compile a complete and consistent body of documentation
before putting the matter up for a vote. This is especially important for correctly classifying
very small, standby, non-Blackstart Resource gensets feeding the aux buses of generation
plants for emergency purposes. Such emergencies include blackouts and max-generation
situations, and in the latter case displacing some of the aux load can temporarily boost the
net amount of power delivered by the plant. 2. Figure I2-5 of the Reference Document
suggests that such standby generators are part of the BES, if the plant totals more than 75
MVA, because they "contribute to the gross aggregate rating of the site." Fig. I2-5 depicts all
units exporting to the grid, however, and we are considering here only standby gensets
feeding aux buses that remain net importers of power. Exclusion E3 may apply, however. Fig.
S1-9b of the Reference Document shows a system composed of several generating plants
and users, but the conclusions reached by the SDT should be unchanged if one drew a box
around the diagram and labeled it a single generating plant. Specifically, the SDT decided that
Exclusion 3 is invoked by the circumstance that the bus fed by the 5 MVA generator at lower
left is exclusively an importer of power, and this ruling should apply as well for standby
gensets that feed aux buses within generation plants. Making such a classification would
require that a Local Network (LN) can exist within a generation plant, as opposed be being
found exclusively in the systems of TOs and DPs. Such an interpretation may be permitted by
the circumstance that the definition of an LN uses the word "transmission" with a lower-case
"t", as opposed the TO and DP-oriented term "Transmission" in the NERC Glossary, but the
LN definition also references serving "retail customer load." This definition should be
changed, or (better) the BES definition should explicitly state that gensets < 20 MVA feeding
power-importing aux buses of generation plants are excluded from the BES. The term
"nameplate rating" should be replaced by the NERC-defined term "Facility Rating" to
harmonize the BES definition with NERC’s standards. 3. Inclusion I2a should be deleted and
I2b should be used to define the threshold for all generating facilities. It is inconsistent to
include a 21 MVA single generator (using I2a) and not include 74.5 MVA aggregated
conglomeration of individual generators (using I2b). Since 75MVA is used as the threshold in
multiple places in this definition, a single generator unit (Facility Rating) at 75 MVA
connected at > 100kV should be the individual unit size threshold. 4. Please specify what size
of reactive power resources is included by I5 (> 75MVAR?).
Individual
Patrick Farrell
Southern California Edison Company
Yes
SCE believes that the revision to I4, the inclusion for dispersed power producing resources, is
a move in the right direction, but we think that additional clarity could be provided by
changing "common point of connection" to "common point of interconnection".
Yes
Clearly identifying "Real" Power makes sense and helps clarify the intent.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
No
These comments are submitted on behalf of the following PPL NERC Registered Affiliates
(PPL): Louisville Gas and Electric Company and Kentucky Utilities Company; PPL Electric
Utilities Corporation, PPL EnergyPlus, LLC; and PPL Generation, LLC, PPL Montana, LLC, and
PPL Susquehanna, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO,
NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP,
GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP. The SDT should consider the comments
of the North American Generator Forum in this respect.
Yes
a. The language of the proposed BES definition is somewhat vague and is therefore difficult
to apply correctly without the Reference Document. The FERC order 773/773a-amended
Reference Document is not complete or final for the phase-2 BES definition, however. Its
exclusion E1 statement is that of phase-1, not phase-2, for example, and a disclaimer on p.1
states that “…this reference document is outdated. Revisions to the document will be
developed at a later date to conform to the definition being developed in Phase 2.” It
appears that the phase-2 BES definition is being rushed through the approval process, and it
would be preferable to take the time to compile a complete and consistent body of
documentation before putting the matter up for a vote. This is especially important for
correctly classifying very small, standby, non-Blackstart Resource gensets feeding the aux
buses of generation plants for emergency purposes. Such emergencies include blackouts and
max-generation situations, and in the latter case displacing some of the aux load can
temporarily boost the net amount of power delivered by the plant. Figure I2-5 of the
Reference Document suggests that such standby generators are part of the BES, if the plant
totals more than 75 MVA, because they "contribute to the gross aggregate rating of the site."
Fig. I2-5 depicts all units exporting to the grid, however, and we are considering here only
standby gensets feeding aux buses that remain net importers of power. Exclusion E3 may
apply, however. Fig. S1-9b of the Reference Document shows a system composed of several
generating plants and users, but the conclusions reached by the SDT should be unchanged if
one drew a box around the diagram and labeled it a single generating plant. Specifically, the
SDT decided that Exclusion 3 is invoked by the circumstance that the bus fed by the 5 MVA
generator at lower left is exclusively an importer of power, and this ruling should apply as
well for standby gensets that feed aux buses within generation plants. Making such a
classification would require that a Local Network (LN) can exist within a generation plant, as
opposed be being found exclusively in the systems of TOs and DPs. Such an interpretation
may be permitted by the circumstance that the definition of an LN uses the word
"transmission" with a lower-case "t", as opposed the TO and DP-oriented term
"Transmission" in the NERC Glossary, but the LN definition also references serving "retail
customer load." This definition should be changed, or (better) the BES definition should
explicitly state that gensets < 20 MVA feeding power-importing aux buses of generation
plants are excluded from the BES. b. The term "nameplate rating" should be replaced by the
NERC-defined term "Facility Rating" to harmonize the BES definition with NERC’s standards.
c. Inclusion I2a should be deleted and I2b should be used to define the threshold for all
generating facilities. It is inconsistent to include a 21 MVA single generator (using I2a) and
not include 74.5 MVA aggregated conglomeration of individual generators (using I2b). Since
75MVA is used as the threshold in multiple places in this definition, a single unit (facility
rating) at 75 MVA connected at > 100kV should be the individual unit size threshold. d.
Please specify what size of reactive power resources is included by I5 (> 75MVAR?).
Group
SERC Planning Standards Subcommittee
Jim Kelley
Yes
Yes
In our opinion, the SDT has improved the E1 exclusion criteria by increasing the 30 kV
threshold to 50 kV. We wish to thank the SDT for its diligence in justifying an increase to 50
kV. However, we still believe that the threshold is too low and would like to see it raised to at
least to 70 kV.
Yes
Yes
E3b: The testing conditions for E3b should be clearly stated, namely for all facilities in service
or for single transmission contingency conditions. We believe that the criteria need to be
anchored so as not to manufacture a justification for inclusion of local network facilities as
BES facilities Add word “normally” between “not” and “transfer” to E3b: Real Power flows
only into the LN and the LN does not normally transfer energy originating outside the LN for
delivery through the LN; and We do not believe that 1 MW of back-feed from local network
facilities to transmission facilities for a few hours of the year constitutes classification of the
local network facilities as BES facilities. We believe that the magnitude of the injections from
the local network should be reviewed in line with other injections into the transmission
system such as a) generators with a nameplate greater than 20 MVA, or b) aggregate
resources greater than 75 MVA. In our opinion, the standard puts additional burden on local
network owners including local subtransmission network owners to prove that their facilities
should be excluded from consideration as BES facilities. In theory, this testing could be
included in the annual TPL contingency analysis, but it may not be possible to complete this
type of analysis before the end of the year for numerous models reflecting varying system
conditions. It was suggested in the last webinar that SCADA data could be used to prove that
there was no back-feed from the local network to the transmission system, but the accuracy
of some SCADA data at low flow levels can be suspect and the SCADA data does not identify
the exact system conditions that were experienced when the SCADA measurements were
recorded, including outages to local subtransmission facilities. We appreciate the work of the
SDT to try and provide a reasonable and balanced approach to the determination of BES
facilities, and within a very short period of time. We ask that the injections into the
transmission network from the various generation and local network sources be considered
on a comparable basis in the determination of BES facilities. The comments expressed herein
represent a consensus of the views of the above named members of the SERC PSS and 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
Scott Langston
City of Tallahassee
Yes
Yes
Yes
No
Individual
Oliver Burke
Entergy Services, Inc.
Agree
SERC OC Review Group comments
Individual
Terry Volkmann
Volkmann Consulting, Inc
No
There is no technical justification to include disperse generation into the BES definition. The
impact of the aggregation is studied and addressed in the FAC-001 and FAC-002 processes.
Once the effects of dispatchability and frequency / voltage control in aggregation are
addressed and mitigated in these processes, the inclusion of each individual generator into
the BES definition provides no further value to the industry and reliability.
Yes
Yes
No
Group
SPP Standards Review Group
Robert Rhodes
Yes
While we don’t have an issue with separating I4 from I2 as in the previous draft, we do have
concern with the wording of the inclusion, especially the phrase ‘primarily designed’. While
the diagram provided in the comment form clearly shows the distinction, it is difficult to pull
it from the wording of I4. Additionally, we are confused by what was explained during the
NERC industry webinar and what is shown in the above figure. The figure and the words in I4
indicate the point of aggregation is included in the BES. The discussion during the webinar
did not include it in the BES.
Yes
Yes
This change has been made to clarify the drafting team’s intent. We would be interested in
knowing what that intent is.
Yes
In the Implementation Plan, delete ‘go’ at the beginning of the 3rd line of the 1st paragraph.
Whitepaper On Page 9, Line 9 of the 1st paragraph, delete the ‘/’. On Page 9, Line 3 of the
2nd paragraph, replace ‘represent’ with ‘represents’. On Page 9, Line 4 of the 2nd paragraph,
replace ‘distribute’ with ‘flow’.
Group
Florida Municipal Power Agency
Frank Gaffney
No
FMPA thanks the SDT for its efforts. Although FMPA agrees with separating I4 from I2, we
believe the SDT made a grammatical / logical error in the new I4. Inclusion I4 as posted
reads: I4 - Dispersed power producing resources consisting of: a) Individual resources that
aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and b) The
system designed primarily for delivering capacity from the point where those resources
aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kV or
above. The logical structure of I4 a) and I4 b) read literally does not reflect the intent of the
SDT. The SDT seems to want to both: i) Identify the intersection of bullet a) and bullet b)
[e.g., only a) vehicles with b) more than 2 axels need to be weighed at a truck stop, e.g., the
subset of a) vehicles and b) with more than two axels] ii) While at the same time describe
what is part of the BES [e.g., a pie is made of a) filling and b) crust, e.g., the addition of a) and
b)]. The use of “and” at the end of bullet a) read literally would be interpreted as adding a)
and b), i.e., a pie being made of filling and crust, and does not limit the scope to the
intersection of bullets a) and b). That is, the BES pie is made of individual resources that
aggregate to > 75 MVA with no criteria over which that aggregation is performed (is it service
territory, geography, within a fence, etc.) and b) the portion of a collector system that carries
> 75 MVA in aggregation. The word “and” cannot perform both functions of adding a)+b)
while at the same time identifying the intersecting subset of set a) and set b), which is what
the SDT seems to be attempting to do. What the team must have meant was: I4 - Dispersed
power producing resources that aggregate to a total capacity greater than 75 MVA (gross
nameplate rating), and that are connected through a system designed primarily for delivering
such capacity from the point at which those resources aggregate to greater than 75 MVA to a
common point of connection at a voltage of 100 kV or above. The BES portion of such
resources includes: a) The individual resources, and b) The system designed primarily for
delivering capacity from the point where those resources aggregate to greater than 75 MVA
to a common point of connection at a voltage of 100 kV or above. This intent is reflected in
the diagram provided by the SDT in the comment form. This grammatical / logic error almost
caused FMPA to vote Negative. The version of I4 posted read literally, an auditor does not
know on what basis the 75 MVA of generation would be integrated, e.g., over the service
territory of the entity? The auditor also is uninformed of whether this includes behind the
meter generation or not. FMPA implores the SDT to correct this grammatical / logical error. If
this error is not corrected, we will likely be changing our vote, and making recommendations
to vote Negative on recirculation / final ballot.
Yes
Yes
Individual
Ryan Walter
Tri-State Generation and Transmission Association, Inc.
No
The NERC draft shows a schematic for resources that aggregate at a single bus location. TriState Generation and Transmission Association, Inc. (Tri-State) has included a drawing (Sent
via email to Wendy Muller (NERC Standards Development Administrator)) that shows four
examples of distributed generation that could have been developed as phases of a single
developer or as multiple developers. The drawings show Tri-State’s interpretation of which
elements (highlighted in yellow) would be included based on the draft BES definition
Inclusion I4. As written, it would include any line element from the point where the
aggregated generation exceeds 75 MVA through the transformer that steps the voltage up to
100 kV or greater and include every dispersed generator attached to the line, even if it is a
solitary unit. Please provide comments as to our interpretation. Inclusion I4a should be
deleted. It does not appear to follow the intent of the FERC Order 773. In Order 773,
paragraph 106 “NERC states that the inclusion is meant to address the dispersed power
producing resources themselves, not the individual elements of the collector systems
operated below 100 kV.” Tri-State agrees with the EEI comment within this paragraph, “that
inclusion I4 applies to generating resources meeting the threshold in the aggregate, not the
individual generating units”. There is no apparent requirement within the Commission
Determination where FERC is requiring this inclusion. Tri-State does not find the inclusion of
individual generating resources as low as 2MVA beneficial to the BES. A loss of a 2MVA
generating resource on low voltages does not pose the same risk as the loss of an aggregated
loss of 75MVA. If inclusion I4a is not deleted, a minimum MVA level for the individual
resource to be included in the BES should be added, just as I2 has. Tri-State recommends the
Standard Drafting Team replace the current ballot’s draft I4 language with: “The system
designed primarily for delivering capacity of dispersed power resources from the point where
those resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.”
Yes
Yes
No
Group
BANC & SMUD
Joe Tarantino
No
Although we believe the Drafting Team has provided vast improvement to the Draft #2 of the
Phase 2-I4 BES Definition SMUD is posting a Negative position for Draft #2 for the following
reasons. Salient Issues: • In accordance with Paragraph 115 of the Commission’s Order 773,
exclude the collector system from the BES definition. o Wind/Solar BES delineation should be
limited the GSU where the total plant capacity is connected at a common point to 100kV or
greater. o During Phase-1, it was suggested that a 75 MVA threshold be established where
the loss of a single element would render the entire 75 MVA of resources unavailable. This
was in lieu of including the individual small-scaled machines as BES to avoid subjecting those
machines to administrative burden for little or no impact on the BES as compared to the
compliance obligation. • Redundant to TPL & TOP standards where loss of the resource(s) for
a single element is addressed in system studies that include evaluation for adequate level of
resources, system impacts and Single Largest Contingencies. • Must include the phrase “(e.g.,
wind or solar)” after “Dispersed power producing resource projects” to fully clarify the
applicability of Inclusion I4. • Support a Standard Authorization Request or other mechanism
to reduce administrative burden for compliance to specific standards (e.g., PRC-004
(Misoperations) & PRC-005 (Maintenance & Testing). The following is suggested wording for
I4 that are associated with the points above: “I4 - Dispersed power producing resource
projects, or portion(s) thereof, designed primarily for supplying wholesale power (e.g., a wind
farm, or solar farm) that aggregate to a total capacity greater than 75 MVA (gross nameplate
rating) at a common point of connection to a voltage of 100 kV or above consisting of: a) The
individual resources, and b) The delivery system designed primarily for delivering capacity
from i) the point where those resources aggregate to the total connected capacity; to ii) a
common point of connection at a voltage of 100 kV or above.” Rationale: 1. “projects …
designed primarily for wholesale…”: Nothing in this posted version distinguishes between
generation for retail (behind the meter) and generation for wholesale. As such, rooftop PVs,
generator assistance programs, or other similar small power-producing incentives, might be
otherwise interpreted as included under I4. 2. “(e.g., a wind farm, or solar farm)”: Because
the SDT’s I4 text-box will be dropped from the final version, we believe this inclusion is
necessary to retain an illustration of the intent. 3. I4.a: While applying BES NERC Reliability
Standards to the management of individual small units is counter-productive and
administratively burdensome, we do agree that differentiating applicability of various
Standards should be specified within those Standards. 4. I4.b: We believe the proposed
wording: a. Appropriately addresses impact to BES reliability. Rather than offering some
illusion for reliability at a lesser impact level, this proposal recognizes that reliability rests in
TPs, BAs, RCs, and TOPs responsibly addressing the single greatest contingency arising from,
and the behavior of, dispersed power producing resources in the aggregate. Enforcing
governance for management to any lesser level is not productive and has no true value to
BES reliability. b. Better aligns with FERC’s Determination within Order 770 paragraph 114. c.
Aligns with FERC’s Determination for I2 within Order 773 paragraph 91. d. Aligns with FERC’s
Determination for I2 within Order 773 paragraph 92.
Yes
Yes
During Phase-1, it was suggested that a 75 MVA threshold be established where the loss of a
single element would render the entire 75 MVA of resources unavailable. This was in lieu of
including the individual small-scaled machines as BES to avoid subjecting those machines to
administrative burden for little or no impact on the BES as compared to the compliance
obligation. (Please refer to response to Q2 for additional details.)
Group
PacifiCorp
Kelly Cumiskey
No
The SDT has made significant progress by separating dispersed power producing resources
from traditional generating resources in Inclusion I2. By including I4 subpart (b), the SDT has
identified the critical element(s) that impact reliability. However, by failing to sufficiently
address the real issue of the impact of the mandatory reliability standards on individual
dispersed power resources, the SDT has perpetuated a gross error identified during phase
one of the BES definition project, by including each “individual” dispersed power producing
resource as potentially within the scope of the BES. During NERC’s August 21, 2013 webinar
on this project, the presenter emphasized the critical nature of the aggregate generation of
dispersed power producing resources for the reliability of the interconnected transmission
system. To that end, Inclusion I4 subpart (a) is inconsistent with NERC’s express statements
concerning the critical nature of the generation in the aggregate. The presenter also
indicated that those reliability standards that apply to the GO/GOP functions should be
addressed via a SAR in order to modify those standards that impose an unreasonable burden
on sectors within the industry without providing a commensurate benefit to reliability.
PacifiCorp believes that the appropriate manner to address this discrepancy is in fact not to
submit a SAR to modify the standards, but rather to first eliminate Inclusion I4 subpart (a) –
and thus remove the collective set of individual resources from within the BES – and then
modify those standards in the future to address any lingering reliability gaps that may apply
to dispersed power producing resources on an individual basis. PacifiCorp recommends the
following language for I4: Dispersed Power Producing Resources: For dispersed power
producing resources that aggregate to a total capacity greater than 75 MVA, the system
designed primarily for delivering capacity from the point where such resources aggregate to
greater than 75 MVA to a common point of connection at a voltage of 100 kV or above. Note:
While individual dispersed power producing resources are not considered part of the BES,
that does not exempt registration as a GO or GOP for those entities that solely own and/or
operate such resources where the aggregate is greater than 75 MVA. Dispersed power
producing resources are small-scale power generation technologies using a system designed
primarily for aggregating capacity providing an alternative to, or an enhancement of, the
traditional electric power system. Examples could include but are not limited to solar,
geothermal, energy storage, flywheels, wind, micro-turbines, and fuel cells. PacifiCorp’s
justification for this revised language is as follows: a dispersed power producing resource
necessarily consists of individual units of a limited size to take advantage of the distributed
nature of the resource (e.g., wind or solar) upon which the facility relies for its fuel source.
One benefit of such facilities’ unit size and geographical distribution is that the facility is not
as susceptible to a substantial loss of generating capability as a single unit of 20 MVA or
greater (the registration threshold for a single generating unit). If the arrayed generators
were each 2 MVA then the probability of losing 20 MVA at the generator level would be
.00000001%. If the units were 5 MVA each the probability of losing all four units at the
generator level would be .01%. The probability of losing a single 20 MVA unit would be 10%.
These variations illustrate that there will be different values depending upon the arrayed
generator’s size. Given the reliability advantage this diversity affords it does not seem
reasonable to treat this type of facility in the same way as a single unit facility of 20 MVA or
greater. As recognized by the SDT, a dispersed generating facility of 75 MVA or greater (NERC
Registry Criterion Section III.c.2) can have an impact on the BES. To recognize this impact and
to also account for the dispersed nature and reliability advantage as described above,
PacifiCorp requests that the SDT exclude individual dispersed power producing resources
from the BES through a revised Inclusion I4 substantially similar to the proposal above. A
technical example of the impact of the loss of an individual wind turbine to the BES is
available from PacifiCorp to the SDT upon request.
Yes
Yes
No
Individual
Alice Ireland
Xcel Energy
No
To be clear, Xcel Energy is strongly supportive of the change made to Exclusion E1, to raise
the exclusion threshold for radial and local networks from 30 kV to 50 kV. However, we are
voting negative due the unnecessary inclusion of dispersed power individual resources in
Inclusion I4(a). We understand that the individual dispersed generators ended up being
included in the Phase I BES definition, but based on the development history, it is clear that
the industry did not believe they should be included and thought they WERE NOT included. It
wasn’t until the guidance document was finalized that it was apparent where the drafting
team landed on the subject. Phase II of this project provides the best opportunity to refine
and improve the BES definition such that industry compliance efforts are focused on
activities that will truly have an impact on reliability. Please see our detail comments and
justifications below: While we strongly support the separation of I2 and I4 and the 75 MVA
threshold for aggregating facilities in Inclusion I4 (b), Xcel Energy continues to disagree with
the inclusion of small individual dispersed generators per Inclusion I4 (a). We provided
alternative language for I4 in the last comment period. That recommendation still stands.
Including individual dispersed generators in the BES definition will cause a huge diversion in
work activities as entities are forced to simultaneously seek relief via the Exception Process
to exclude reliability insignificant individual dispersed generators from their programs while
at the same time attempting to modify their existing compliance programs to accommodate
individual dispersed generators in the event that the exception applications are not
approved. NERC and the Regions will be faced with a huge backlog of exception requests for
small distributed generators while Generator Owners with dispersed generating assets will
struggle to implement reliability standards that were never drafted with the intent of being
applicable to anything but large scale generating stations. In the August 21, 2013 webinar,
the BES definition drafting team indicated that its justification for the 75 MVA aggregating
threshold in I4 (b) was that 75 MVA is the level that the drafting team believes that single
failures resulting in the loss of generation could have an appreciable impact on the grid. It
seems inconsistent that a 2 MVA individual dispersed generator is deemed significant to
reliability but the equipment that is utilized to connect individual dispersed generators
totaling to <75 MVA is deemed not significant to reliability. Furthermore, with no
requirement that the BES be contiguous, how can individual 2 MVA wind turbine generator
at a >75 MVA wind farm have a greater effect on BES reliability than an identical individual 2
MVA wind turbine at a <75 MVA wind farm? With no technical rationale or difference in
effects on BES reliability, how can identical 2 MVA units legally be treated so differently? In
the Consideration of Comments document for the first draft of Phase II BES definition, the
Drafting Team acknowledged that there are both existing and pending reliability standards
which likely will need to be reviewed and revised to clarify or correct the applicability of the
standard requirements to small scale generation and recommended that the industry create
a SAR to call for this action. Relative to the approval and implementation time frames being
discussed for the new BES definition, we do not believe any such action could be taken in a
timely enough fashion to resolve industry uncertainty and avoid major regulatory burden
with no commensurate improvement in grid reliability. Examples: • PRC-005-2 Protection
System testing – the based relay test requirements were developed with large generators in
mind, and differ significantly from requirements in DOE Order 661A, of 2005 that requires
wind plants to meet Low Voltage Ride-Through (LVRT) and Power Factor Design Criteria.
These standards significantly change the protection scheme applied to individual turbines,
and is not addressed here. Wind turbine protection systems are often integral to the wind
farm control system and the PRC-005-2 requirements were developed for protection
equipment typically applied on large scale generation not wind farm control systems. • TOP002 Normal Operations Planning – Under R14 of this standard, an unplanned outage for any
individual wind turbine would require a status notification report from the GO to the
TO/TOP. This level of reporting, at typically less than 3 MVA, is much less that any practical
reliability threshold, and would simply result in a documentation effort with no value. Similar
concerns exist for FAC-008-3, PRC-001-1, PRC-004-2a, PRC-019-1, PRC-024-1, and PRC-025-1,
and other standards where it is quite evident that small scale dispersed generators were not
considered during the standard's development. Unless Inclusion I4 (a) is eliminated, we do
not believe implementation of the new BES definition should go forward until all reliability
standards have been reviewed and revised as necessary to clarify the applicability to
individual dispersed generating assets. What reliability benefit is there to a "bright line" BES
definition if there is not a corresponding clarity in the applicability of reliability standards to
the elements deemed to be included in the BES?
Yes
Xcel Energy strongly supports this modification.
Yes
No
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
Yes
No
Individual
Russel Mountjoy
MRO
No
MRO recommends the removal of I4 a) and 14b Industry requested the point of aggregation
to be added in place of the individual generators themselves, not as well. The inclusion of
this statement, I4 b, tends to lead industry to believe the individual generators will still
remain under the new definition of the BES in addition to the aggregation point. The addition
of individual resources which are not material to the BES creates undue burden on the
registered entities and regional entities through the process of identifying these assets in
order to have to apply for an exception due to these assets not being material to the BES.
Proposed re-write of I4: Aggregate point where dispersed power producing resources
aggregate at a common bus to a total capacity greater than 75 MVA (gross name plate rating)
linking to a common point of connection at a voltage of 100kV or above.
Yes
Yes
No
Group
Duke Energy
Colby Bellville
Yes
Duke Energy agrees with the changes made by the SDT.
Yes
Duke Energy agrees with the modifications made by the SDT.
Yes
No
Individual
David Kiguel (by Ayesha Sabouba)
Hydro One
Yes
We reluctantly support the separation of I2 and I4 because we believe that their wordings in
the BES definition as approved by the industry, NERC BOT, FERC and applicable governmental
authorities in Canada should have been retained. In our opinion, I4 is meant for renewable
energy resources (in particular Wind). These resources are inherently different when
considered for planning and for real time operations. This change will essentially designate
every element of a wind farm above 75MVA to its interconnection at 100kV as a BES element
including the medium voltage collector systems (less than 50kV) adding burden which may
not be necessary. Further, it is not clear what and how standards will apply to collector
systems designated as BES.
Yes
We agree that 50kV is more reasonable and are voting positively to the change made by SDT.
This change was essentially initiated to address a FERC directive in its Order 773. However it
should be noted that the demarcation point between transmission and distribution may be
different in non FERC jurisdictions, such as Canadian provinces. In establishing voltage
thresholds, NERC needs to consider non-US legislated demarcation points, and the standard
development process must make allowances for such regulatory and/or jurisdictional
differences and frameworks consistent with NUC 001 and TPL footnote b. We suggest that
NERC and the SDT consider revising Note 2 to read as follows: Note 2 – The presence of a
contiguous loop, operated at a voltage level of 50 kV or less, between configurations being
considered as radial systems, does not affect this exclusion. Non-US Registered Entities can
adopt the same voltage level or should implemented in a manner that is consistent with, or
under the direction of, the applicable governmental authority or its agency.
Yes
Yes
In Canada, local load reliability requirements are under the provincial authority of local
regulators such as the Ontario Energy Board in Ontario. We understand that NERC needs to
follow FERC Orders and directives. In our opinion NERC must ensure that any provisions
within the BES definition and/or NERC standards that are to address load reliability and load
supply continuity issues and NOT interconnected BES reliability should be limited to the FERC
jurisdiction only. Accordingly we suggest that when addressing such requirements in a
standard it must include that for a non-US Registered Entity it should be implemented in a
manner that is consistent with, or under the direction of, the applicable governmental
authority or its agency in the non-US jurisdiction. Good examples to address these issues are
through the Standards process as was done for NUC 001 and TPL001 Footnote b.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
No
ATC appreciates the changes the SDT made to I4, however, believe the wording of I4a still
does not adequately communicate the desired treatment of small dispersed power
producing resources as an aggregate, rather than an individual basis, when the aggregate
capacity is 75 MVA or more. To address this issue, we suggest the following wording change
to I4a, “Aggregate of dispersed resources when they aggregate to a total capacity of greater
than 75 MVA (gross nameplate rating, and”
Yes
Yes
Yes
ATC has the following additional comment for consideration by the SDT: • Exclusion 3b does
not currently define the limited set of conditions entities are to consider when determining if
real power flows only into the local network (LN). Without this clarification, entities will have
no certainty regarding the exclusion determination made, which can have a material impact
on the entity under all of the NERC standards. ATC recommends the following revision to
E3b: E3b) Real Power flows only into the LN under intact system and most severe single
contingency conditions and the LN does not transfer energy originating outside the LN for
delivery through the LN; and’ This revision is warranted for the reason noted above. In
addition, the language is consistent with how the system is operated under the NERC TOP
standards and the proposed addition matches NERC’s own statements to the FERC as
recorded in paragraph 71 of FERC Order 773-A. As noted in the same paragraph, FERC agreed
with NERC’s reasoning. Therefore, this clarification should be recorded in the BES definition.
Individual
John Robertson
First WInd
No
First Wind supports the separation of I2 and I4 and the 75 MVA threshold for aggregating
facilities in Inclusion I4 (b), and the exclusion of collector system components that aggregate
less than 75 MVA of generation, First Wind disagrees with the inclusion of small individual
dispersed generators per Inclusion I4 (a). This problem can be resolved by either removing I4
(a) in its entirety or revising it to clarify that the only BES-relevant standards that apply to
individual dispersed generators are those that affirmatively state that they apply to dispersed
generators. While individual generators were included in the Phase I BES definition, Phase II
of this project provides an opportunity to refine and improve the BES definition such that
industry compliance efforts are focused on activities that will truly have a beneficial impact
on reliability. Including individual dispersed generators in the BES definition will cause a
major diversion away from efforts that improve BES reliability, as entities are forced to
simultaneously seek relief via the Exception Process to exclude individual dispersed
generators that are insignificant from a reliability standpoint from their programs while at
the same time attempting to modify their existing compliance programs to accommodate
individual dispersed generators in the event that the exception applications are not
approved. Regions will be faced with a huge backlog of exception requests for small
distributed generators while Generator Owners with dispersed generating assets struggle to
implement reliability standards that were never drafted with the intent of being applicable to
anything but large scale generating stations. As a result, proceeding with the BES definition
as currently drafted would actually impair, rather than improve, bulk electric system
reliability. First Wind supports the exclusion of collector system components that aggregate
less than 75 MVA, it seems inconsistent that a 1-2 MVA individual dispersed generator is
deemed significant to reliability but the equipment that is utilized to connect multiple
dispersed generators totaling up to 75 MVA is deemed not significant to reliability. The logic
that led to the exclusion of collector system equipment that aggregates less than 75 MVA, as
well as the logic expressed on the webinar that 75 MVA is the threshold at which the loss of
generation could have an impact on BES reliability, argues for also excluding individual
dispersed generators. Furthermore, what is the logic of including individual 1-2 MVA wind
turbine generator at a >75 MVA wind farm while excluding an individual wind turbine at a
<75 MVA wind farm? With no technical rationale or difference in effects on BES reliability,
how can identical 2 MVA units be treated so differently? The only compelling reason for
applying BES standards to individual dispersed generators would be if there were a real risk
of a common mode failure affecting a large share of the dispersed generators in a >75 MVA
wind plant. However, per FERC Order 661A, wind turbine generators already comply with
voltage and frequency ride-through standards that are far more stringent than those apply to
other types of generators. As a result, if a common mode failure caused by a grid disturbance
were to affect the wind turbines in a >75 MVA wind plant, the impact on the wind plant
would be irrelevant for grid reliability because the voltage and/or frequency deviation would
have already caused most if not all of the conventional generators in the grid operating area
to trip offline. No compelling rationale has been offered for why including individual
dispersed wind turbine generators in the BES definition will improve grid reliability.
Yes
Yes
No
Individual
Anthony Jablonski
ReliabilityFirst
Yes
Even though ReliabilityFirst votes in the Affirmative, ReliabilityFirst is aware of some
concerns among Registered Entities for the potential issue of individual wind units (i.e. single
generators) being required to register based on the language of the revised definitions
(specifically I4). Though ReliabilityFirst staff agrees with I4 and does not believe this is an
issue, ReliabilityFirst recommends NERC and the Regional Entities come up with a common
understanding on how Entities are registered based on their ownership of wind units which
are designated as BES through the new definition.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
No
FOR: Inclusion I4 REPLACE: Complete wording of I4 WITH: “I4 - Dispersed power producing
resource projects , or portion(s) thereof, designed primarily for supplying wholesale power
(e.g., a wind farm, or solar farm) that aggregate to a total capacity greater than 75 MVA
(gross nameplate rating) at a common point of connection to a voltage of 100 kV or above
consisting of: a) The individual resources, and b) The delivery system designed primarily for
delivering capacity from i) the point where those resources aggregate to the total connected
capacity; to ii) a common point of connection at a voltage of 100 kV or above.” RATIONALE:
(1)• “projects … designed primarily for wholesale” – nothing in this posted version
distinguishes between generation for retail (behind the meter) and generation for wholesale.
As such roof-top PVs, generator assistance programs, or other similar small power-producing
incentives, might be otherwise interpreted as included under I4. (2)• “(e.g., a wind farm, or
solar farm)” – Because the SDT’s I4 text-box will be dropped from the final version, we
believe this inclusion is necessary to retain an illustration of the intent. (3)• I4.a - While
imposing BES Standards of governance toward management of individual small units is
counter-productive and administratively burdensome, we do agree that differentiating
applicability to various Standards should be specified through those Standards. To that end,
we are dedicated to drafting and vigorously promoting a SAR to appropriately address
dispersed power producing resource applicability within individual NERC Standards. (4)• I4.b
– We believe our proposed wording: o Appropriately addresses impact to BES reliability.
Rather than offering some illusion for reliability at a lesser impact level, this proposal
recognizes that reliability rests in TPs, BAs, RCs, and TOPs responsibly addressing the single
greatest contingency arising from, and the behavior of, dispersed power producing resources
in the aggregate. Enforcing governance for management to any lesser level is not productive
and has no true value to BES reliability. o Better aligns with FERC’s Determination within
Order 770 paragraph 114. o Aligns with FERC’s Determination for I2 within Order 773
paragraph 91. o Aligns with FERC’s Determination for I2 within Order 773 paragraph 92.
ALTERNATE APPROACH: In the consideration of comments, the drafting team indicated that a
SAR might be submitted to appropriately adjust GO and GOP standards requirements for
dispersed generating facilities. We agree that is the approach to undertake. In order to
support this approach, I4 should be deleted to avoid the situation where inappropriate
provisions could become effective and compliance become difficult or impossible for entities
until work is completed through the SAR to adjust those requirements. In the filing with FERC
this procedure could be explained so that FERC can be assured that their approval of
inclusion of dispersed generating facilities in the phase I order will be appropriately
implemented. AECI also supports NAGF's recommendation for the SDT with regard to I2
changes.
Yes
AECI appreciates the SDT's willingness to tackle this issue and provide a higher kV level than
0, as well as its technical justification.
Yes
Yes
AECI supports the NAGF's draft comment for concern, duplicated immediately below: "The
language of the proposed BES definition is rather convoluted and is therefore difficult to
apply correctly without the Reference Document. The FERC order 773/773a-amended
Reference Document is not complete or final for the phase-2 BES definition, however. Its
exclusion E1 statement is that of phase-1, not phase-2, for example, and a disclaimer on p.1
states that “…this reference document is outdated. Revisions to the document will be
developed at a later date to conform to the definition being developed in Phase 2.” It
appears that the phase-2 BES definition is being rushed through the approval process, and it
would be preferable to take the time to compile a complete and consistent body of
documentation before putting the matter up for a vote. This is especially important for
correctly classifying very small, standby, non-Blackstart Resource gensets feeding the aux
buses of generation plants for emergency purposes. Such emergencies include blackouts and
max-generation situations, and in the latter case displacing some of the aux load can
temporarily boost the net amount of power delivered by the plant. Figure I2-5 of the
Reference Document suggests that such standby generators are part of the BES, if the plant
totals more than 75 MVA, because they, "contribute to the gross aggregate rating of the
site." Fig. I2-5 depicts all units exporting to the grid, however, and we are considering here
only standby gensets feeding aux buses that remain net importers of power. Exclusion E3
may apply, however. Fig. S1-9b of the Reference Document shows a system composed of
several generating plants and users, but the conclusions reached by the SDT should be
unchanged if one drew a box around the diagram and labeled it a single generating plant.
Specifically, the SDT decided that Exclusion 3 is invoked by the circumstance that the bus fed
by the 5 MVA generator at lower left is exclusively an importer of power, and this ruling
should apply as well for standby gensets that feed aux buses within generation plants.
Making such a classification would require that a Local Network (LN) can exist within a
generation plant, as opposed be being found exclusively in the systems of TOs and DPs. Such
an interpretation may be permitted by the circumstance that the definition of an LN uses the
word "transmission" with a lower-case "t", as opposed the TO and DP-oriented term
"Transmission" in the NERC Glossary, but the LN definition also references serving "retail
customer load." This definition should be changed, or (better) the BES definition should
explicitly state that gensets < 20 MVA feeding power-importing aux buses of generation
plants are excluded from the BES. Additionally, the MVA size of reactive power generator
that is included by I5 should be specificed. "
Group
ACES Standards Collaborators
Ben Engelby
Yes
(1) We thank the drafting team for separating dispersed power producing resources to a
separate inclusion category. This avoids some of the confusion in the prior posting. (2) We
have a question regarding the diagram provided in the comment form. Why is each
generating unit considered a part of the BES? Wouldn’t the point of aggregation be the first
BES element? If a single dispersed power producing resource fails, there is no impact on the
BES. We request the drafting team consider this aspect.
Yes
We thank the drafting team for increasing the minimum threshold to 50 kV for sub-100 kV
looped radial systems.
Yes
Yes
We understand that NERC has developed a process for handling exception requests. We are
concerned this process could be similar to the TFE exception process. We recommend that
the exception process should be included with future BES definition postings with the
opportunity to comment on the process.
Individual
Michael Goggin
American Wind Energy Association
No
While we strongly support the separation of I2 and I4 and the 75 MVA threshold for
aggregating facilities in Inclusion I4 (b), and the exclusion of collector system components
that aggregate less than 75 MVA of generation, we still strongly disagree with the inclusion of
small individual dispersed generators per Inclusion I4 (a). This problem can be resolved by
either removing I4 (a) in its entirety or revising it to clarify that the only BES-relevant
standards that apply to individual dispersed generators are those that affirmatively state that
they apply to dispersed generators. While individual generators were included in the Phase I
BES definition, that is not a compelling reason why they should also be included in Phase II.
Phase II of this project provides an opportunity to refine and improve the BES definition such
that industry compliance efforts are focused on activities that will truly have a beneficial
impact on reliability. Including individual dispersed generators in the BES definition will cause
a major diversion away from efforts that improve BES reliability, as entities are forced to
simultaneously seek relief via the Exception Process to exclude individual dispersed
generators that are insignificant from a reliability standpoint from their programs while at
the same time attempting to modify their existing compliance programs to accommodate
individual dispersed generators in the event that the exception applications are not
approved. With more than 45,000 wind turbines installed in the U.S. and the vast majority of
them in wind plants larger than 75 MVA, NERC will be faced with a huge backlog of exception
requests for small distributed generators while Generator Owners with dispersed generating
assets struggle to implement reliability standards that were never drafted with the intent of
being applicable to anything but large scale generating stations. As a result, proceeding with
the BES definition as currently drafted would actually impair, rather than improve, bulk
electric system reliability. In the Consideration of Comments document for the first draft of
Phase II BES definition, the Drafting Team acknowledged that there are both existing and
pending reliability standards which likely will need to be reviewed and revised to clarify or
correct the applicability of the standard requirements to small-scale generation and
recommended that the industry create a SAR to call for this action. Relative to the approval
and implementation time frames being discussed for the new BES definition, we do not
believe any such action could be taken in a timely enough fashion to resolve industry
uncertainty and avoid a major regulatory burden that would distract from efforts that
actually improve grid reliability. Examples of standards that were not drafted with small
dispersed generators in mind include: • PRC-005-2 Protection System testing – the relay test
requirements were developed with large generators in mind, and differ significantly from
requirements in FERC Order 661A, of 2005 that require wind plants to meet Low Voltage
Ride-Through (LVRT) and Power Factor Design Criteria. These standards significantly change
the protection scheme applied to individual turbines, and there is no clarity about how they
should be applied. Wind turbine protection systems are often integral to the wind farm
control system and the PRC-005-2 requirements were developed for protection equipment
typically applied to large-scale generation, not wind farm control systems. • TOP-002 Normal
Operations Planning – Under R14 of this standard, an unplanned outage for any individual
wind turbine would require a status notification report from the GO to the TO/TOP. While
such a report can be important for large central station generation, it would provide no value
for a small individual wind turbine generator. This level of reporting, at typically less than 3
MVA, is much lower that any practical reliability threshold, and would simply result in a
documentation effort with no value. Similar concerns exist for FAC-008-3, PRC-001-1, PRC004-2a, PRC-019-1, PRC-024-1, and PRC-025-1, and other standards in which small-scale
dispersed generators were not considered during the standards’ development. Unless
Inclusion I4 (a) is eliminated, or significantly revised to clarify that the only BES-relevant
standards that apply to dispersed generators are those that affirmatively state that they
apply to dispersed generators, we do not believe implementation of the new BES definition
should go forward until all reliability standards have been reviewed and revised as necessary
to clarify the applicability to individual dispersed generating assets. What reliability benefit is
there to a "bright line" BES definition if there is not a corresponding clarity in the applicability
of reliability standards to the elements deemed to be included in the BES? On the August 21,
2013 webinar, the BES definition drafting team indicated that its justification for the 75 MVA
aggregating threshold in I4 (b) was that 75 MVA is the level that the drafting team believes
that single failures resulting in the loss of generation could have an appreciable impact on
the grid. While we support the exclusion of collector system components that aggregate less
than 75 MVA, it seems inconsistent that a 2 MVA individual dispersed generator is deemed
significant to reliability but the equipment that is utilized to connect multiple dispersed
generators totaling up to 75 MVA is deemed not significant to reliability. The logic that led to
the exclusion of collector system equipment that aggregates less than 75 MVA, as well as the
logic expressed on the webinar that 75 MVA is the threshold at which the loss of generation
could have an impact on BES reliability, argues for also excluding individual dispersed
generators. Furthermore, what is the logic of including individual 2 MVA wind turbine
generator at a >75 MVA wind farm while excluding individual 2 MVA wind turbine at a <75
MVA wind farm? With no technical rationale or difference in effects on BES reliability, how
can identical 2 MVA units be treated so differently? The only compelling reason for applying
BES standards to individual dispersed generators would be if there were a real risk of an
abrupt common mode failure affecting a large share of the dispersed generators in a >75
MVA wind plant. However, per FERC Order 661A, wind turbine generators already comply
with voltage and frequency ride-through standards that are far more stringent than those
that apply to other types of generators. As a result, if a common mode failure caused by a
grid disturbance were to affect the wind turbines in a >75 MVA wind plant, the impact on the
wind plant would be irrelevant for grid reliability because the voltage and/or frequency
deviation would have already caused most if not all of the conventional generators in the
grid operating area to trip offline. While weather-driven changes in wind speed can
significantly change the aggregate output of a wind plant, those changes in output occur too
gradually to pose a risk to bulk power system reliability, and regardless such changes in
output would not be regulated or mitigated by BES-relevant standards. No compelling
rationale has been offered for why including individual dispersed wind turbine generators in
the BES definition will improve grid reliability.
Individual
Dan Inman
Minnkota Power Cooperative
No
During the 8/21/2013 webinar the presenter emphasized the critical nature of the aggregate
generation of dispersed power producing resources to the reliability of the interconnected
transmission system. I4 subpart (a) is inconsistent with the stated critical nature of the
aggregate generation. The presenter also indicated that standards that apply to GO/GOP
associated standards should be addressed via a SAR to correct reliability standards that
impose a burden on the industry without providing a significant benefit to reliability. The
appropriate manner to address this discrepancy is not to submit a SAR to modify the
standards that would inappropriately invoke requirements on individual generators due to
their inclusion in the BES definition, but to eliminate I4 subpart (a) and modify standards in
the future to address any reliability issues that may need the imposition of requirements for
individual dispersed power producing resources. The following language is suggested for a
revised I4: I4 - Dispersed power producing resources consisting of the system designed
primarily for delivering capacity from the point where those resources aggregate to greater
than 75 MVA to a common point of connection at a voltage of 100 kV or above. Proceeding in
this manner will avoid temporary inappropriate standards requirements being applied to
individual dispersed power resources and still address the individual resources in standards
where needed to support reliability.
Yes
Yes
No
Individual
Richard Vine
California Independent System Operator
No
It is clear that the SDT has taken significant action to distinguish between dispersed power
producing resources and traditional generating resources through modification of inclusion
I4. However, the California ISO is concerned that the new verbiage under I4 a), as well as the
color-coded diagram included on the comment form to provide clarification of BES elements,
actually results in ambiguity as to whether each individual power producing resource must
be treated as a BES Element. In particular, use of the phrase “Individual resources that
aggregate…” under I4 a), along with use of the word “and” between I4 a) and I4 b), leaves
open to interpretation whether each individual power producing resource (e.g., each wind
turbine within a wind farm that aggregates to greater than 75 MVA) must be treated as a BES
element or whether only the aggregated whole is a BES element. Though it may be that the
SDT meant to capture that the combination of all aggregated resources and the delivery
system together comprise a BES element, it could be construed that each individual resource
under a) is a BES element and the system for delivering capacity referred to under b) is a BES
element. This is further confused by the drawing included on the comment form which uses a
blue color to identify each individual power producing resource and uses the same blue color
to identify the system for delivering capacity. The legend in the comment box above this
drawing states “Green identifies non-BES portions of the Collector System. Blue identifies the
dispersed power producing resources and BES Elements.” The ISO is concerned that this
ambiguity may create uncertainty regarding whether particular Reliability Standard
requirements apply only to the aggregated resource as a whole or to the individual power
producing resources that comprise the aggregated resource, which is a matter that is better
addressed on a Standard-specific basis. In light of this ambiguity, the ISO is abstaining and
recommends that the SDT clarify its definition so that the focus is on aggregated resource
rather than the individual components.
Individual
Spencer Tacke
Modesto Irrigation District
No
No
Yes
I voted NO for the following reasons: 1. WECC studies have shown that there are thousands
of MWs of wind and PV generating plants currently on-line, and thousands of MWs under
development, in the WECC system, of 20 MW and less capacity units. Ignoring the impacts of
these units on the BES would be a mistake, as recent studies by the WECC MVWG (Modeling
and Validation Work Group) have shown (i.e., June 2013 Meeting). 2. The revisions have
made the definition of the BES so complicated, that the definition is no longer in a form that
can be applied in a straight forward and reasonable manner. Also, there are no technical
justifications provided for some of the exclusion criteria (e.g, 75 MVA ). 3. The best way to
define the BES is by using the engineering methodology developed by the WECC BES
Definition Task Force, and published in May 2010. That study work showed that for the
location in question to have a material impact to the interconnected bulk electric power
system, there must be an equivalent short circuit MVA exceeding 6000 at that location.
Thank you.
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
No
Snohomish supports the Project 2010-17 – Definition of the BES (Phase 2) Standard Drafting
Team in its efforts to clarify the BES definition. Although Snohomish supports the current
definition and will be voting affirmative, we are concerned with the compliance burden to
small dispersed generators that typically are less than 2 MW and have capacity factors in the
25 to 35% range, and may be inclined to change our position if the following issues are not
resolved. Snohomish believes these concerns can be addressed within the Reliability
Standards applicable to GO/GOPs or with the suggested changes below”. 1.Replace the
current ballot’s draft I4 language: “I4 - Dispersed power producing resources consisting of: a)
Individual resources that aggregate to a total capacity greater than 75 MVA (gross nameplate
rating), and b) The system designed primarily for delivering capacity from the point where
those resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.” With the proposed comment I4 language: “I4 - Dispersed power
producing resource projects , or portion(s) thereof, designed primarily for supplying
wholesale power (e.g., a wind farm, or solar farm) that aggregate to a total capacity greater
than 75 MVA (gross nameplate rating) at a common point of connection to a voltage of 100
kV or above consisting of: a) The individual resources, and b) The delivery system designed
primarily for delivering capacity from i) the point where those resources aggregate with a
total connected capacity greater than 75MVA; to ii) a common point of connection at a
voltage of 100 kV or above.” Rationale: “projects … designed primarily for wholesale” –
nothing in the currently posted version of Inclusion I4 distinguishes between generation for
retail (behind the meter) and generation for wholesale. As such roof-top PVs, generator
assistance programs, or other similar small power-producing incentives, might be otherwise
interpreted as included under I4. There is a real possibility that, with net metering laws, tax
incentives, and related public policies strongly favoring the development of, for example,
small, individually-owned solar PV systems, those small systems could easily exceed the 75
MVA thresholds in the aggregate. Considered individually, these small systems have no
discernible impact on the reliable operation of the BES. With sufficient market penetration,
these systems might conceivably have some impact on the BES, but mediating that impact
should be the responsibility of TPs, BAs, TOPs, and other system operators. The regulatory
burden imposed on small owners of individual distributed generation systems that would
result from classifying such small generators as part of the BES would be significant, and a
strong disincentive running contrary to current public policy favoring such systems. Yet,
because such small systems have no impact on the reliable operation of the BES, extending
regulation in this way would have no benefit for BES reliability. • “(e.g., a wind farm, or solar
farm)” – Because the SDT’s I4 text-box will be dropped from the final version, we believe this
language is necessary to clearly express the intent of the BES to cover utility-scale wind
farms, solar farms, and similar installations that consist of many relatively small units that are
aggregated for wholesale while excluding small, individually-owned systems, such as rooftop
solar PV arrays, that are not aggregated for the wholesale market but are owned by and
benefit individual retail customers • I4.a - Imposing BES related Reliability Standards on
individual small units is counter-productive and administratively burdensome. To the extent
that applying individual Reliability Standards to such small, non-aggregated units is
demonstrably necessary to protect BES reliability, application should be governed by the
language of individual Standards rather than by classifying such small systems as BES. To that
end, we are dedicated to drafting and vigorously promoting a SAR to appropriately address
the applicability of individual NERC Standards to dispersed power-producing resources. • I4.b
– We believe our proposed wording: oAppropriately addresses impact to BES reliability. The
proposed language recognizes that reliability rests depends on TPs, BAs, RCs, and TOPs
responsibly addressing the single greatest contingency arising from, and the behavior of,
dispersed power producing resources in the aggregate. Enforcing reliability standards on the
owners of small, dispersed, and non-aggregated resources is not productive and has no true
value to BES reliability. Better aligns with FERC’s Determination in Order 773 paragraph 114. ,
where FERC determined that it will not direct NERC to include collector systems within wind
farms and similar generation systems in the BES through Inclusion I4. oAligns with FERC’s
Determination for I2 in Order 773 paragraph 91 and 92, that multiple step-up transformers
that connect generators to the BES at above 100-kV should be included in the BES, while
connections at lower voltages that operate as part of a local distribution system should not
be classified as part of the BES.
Yes
Yes
No
*Figure submitted by Tri-State G&T referenced in Q1 comments:
http://www.nerc.com/pa/Stand/Documents/BES_I4_Clarification_for_Included_Elements_09042013.pdf
Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Phase 2
Additional Ballot Results
Now Available
An additional ballot for Phase 2 of the Definition of Bulk Electric System (DBES) concluded at 8 p.m.
Eastern on Wednesday, September 4, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results for
the additional ballot.
Approval
Quorum: 78.68%
Approval: 66.11%
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.
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
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010-17 Definition of BES - Phase 2
Password
Ballot Period: 8/26/2013 - 9/4/2013
Log in
Ballot Type: Additional Ballot
Total # Votes: 310
Register
Total Ballot Pool: 394
Quorum: 78.68 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
66.11 %
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
47
0.627
28
0.373
0
10
20
8
0.2
2
0.2
0
0
0
4
2
90
1
36
0.563
28
0.438
0
6
20
36
1
18
0.643
10
0.357
0
1
7
88
1
33
0.611
21
0.389
0
7
27
51
1
26
0.619
16
0.381
0
3
6
2
0.1
1
0.1
0
0
0
0
1
2
0.1
1
0.1
0
0
0
0
1
4
0.4
2
0.2
2
0.2
0
0
0
8
0.8
7
0.7
1
0.1
0
0
0
394
6.6
173
4.363
106
2.238
0
31
84
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
Ameren Services
Eric Scott
Negative
1
American Transmission Company, LLC
Andrew Z Pusztai
Negative
1
Arizona Public Service Co.
Robert Smith
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
NERC
Notes
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC Standards
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Glen Sutton
James Armke
Heather Rosentrater
1
Balancing Authority of Northern California
Kevin Smith
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
1
Central Electric Power Cooperative
Michael B Bax
1
1
Kevin J Lyons
Joseph Turano Jr.
Affirmative
Chang G Choi
Affirmative
1
1
Central Iowa Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Daniel S Langston
Jack Stamper
Affirmative
Affirmative
1
Cleco Power LLC
Danny McDaniel
1
1
1
1
1
1
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dominion Virginia Power
Duke Energy Carolina
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Michael S Crowley
Douglas E. Hils
1
East Kentucky Power Coop.
Amber Anderson
Negative
1
1
1
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Dennis Malone
Oliver A Burke
William J Smith
Affirmative
Affirmative
Affirmative
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
1
1
1
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Bob Solomon
Affirmative
1
Florida Power & Light Co.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
1
Hydro-Quebec TransEnergie
Martin Boisvert
1
Molly Devine
Affirmative
Michael Moltane
Affirmative
1
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
Jim D Cyrulewski
Affirmative
1
KAMO Electric Cooperative
Walter Kenyon
1
1
1
1
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
John Chin
1
Lincoln Electric System
Doug Bantam
Negative
1
1
Long Island Power Authority
Lower Colorado River Authority
Robert Ganley
Martyn Turner
Affirmative
1
1
1
1
M & A Electric Power Cooperative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
Ajay Garg
William Price
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
Negative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
(AECI)
1
1
1
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Nazra S Gladu
Danny Dees
Allan Long
Affirmative
Abstain
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
Minnesota Power, Inc.
Randi K. Nyholm
Negative
1
Minnkota Power Coop. Inc.
Daniel L Inman
Negative
1
Muscatine Power & Water
Andrew J Kurriger
Negative
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Affirmative
1
Nebraska Public Power District
Cole C Brodine
Negative
1
1
1
1
New Brunswick Power Transmission
Corporation
New York Power Authority
New York State Electric & Gas Corp.
North Carolina Electric Membership Corp.
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
Randy MacDonald
Bruce Metruck
Raymond P Kinney
Robert Thompson
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
Northeast Utilities
David Boguslawski
1
Northern Indiana Public Service Co.
Julaine Dyke
1
NorthWestern Energy
John Canavan
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NIPSCO)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
– American
Electric
Power)
Ohio Valley Electric Corp.
Robert Mattey
Negative
1
1
1
1
1
1
1
1
Oklahoma Gas and Electric Co.
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Terri Pyle
Jen Fiegel
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
David Thorne
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
1
PPL Electric Utilities Corp.
Brenda L Truhe
Negative
1
1
Laurie Williams
Kenneth D. Brown
Abstain
1
1
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.
1
Sacramento Municipal Utility District
Tim Kelley
1
1
Salt River Project
San Diego Gas & Electric
Robert Kondziolka
Will Speer
Dale Dunckel
Affirmative
Denise M Lietz
John C. Allen
Affirmative
Affirmative
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SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
1
1
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (MG&E)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Scott Bos)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted
under the title
of 'PPL NERC
Registered
Affiliates')
COMMENT
RECEIVED
NERC Standards
1
SaskPower
Wayne Guttormson
1
Seattle City Light
Pawel Krupa
Negative
1
Sho-Me Power Electric Cooperative
Denise Stevens
Negative
1
1
1
1
1
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Affirmative
Affirmative
Affirmative
Abstain
Abstain
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
1
1
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tennessee Valley Authority
John Shaver
Noman Lee Williams
Howell D Scott
Affirmative
Affirmative
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
1
1
1
1
1
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
2
BC Hydro
2
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
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Marie Knox
Alden Briggs
stephanie monzon
Charles H. Yeung
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
3
AEP
Michael E Deloach
Negative
3
Alabama Power Company
Robert S Moore
Negative
3
Alameda Municipal Power
Douglas Draeger
3
Ameren Services
Mark Peters
3
Arkansas Electric Cooperative Corporation
Philip Huff
3
Associated Electric Cooperative, Inc.
Chris W Bolick
3
3
3
3
3
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
3
Central Electric Power Cooperative
Adam M Weber
3
3
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
Thomas C Duffy
Steve Alexanderson
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SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
- American
Electric
Power)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
NERC Standards
3
3
3
3
3
3
3
3
3
City of Austin dba Austin Energy
City of Farmington
City of Palo Alto
City of Redding
City of Tallahassee
City of Ukiah
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Andrew Gallo
Linda R Jacobson
Eric R Scott
Bill Hughes
Bill R Fowler
Colin Murphey
Charles Morgan
John Bee
Peter T Yost
3
Consumers Energy Company
Gerald G Farringer
3
3
3
3
3
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
3
East Kentucky Power Coop.
Patrick Woods
3
3
3
3
3
3
3
El Paso Electric Company
Entergy
Fayetteville Public Works Commission
FirstEnergy Corp.
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Tracy Van Slyke
Joel T Plessinger
Allen R Wallace
Cindy E Stewart
John M Goroski
Joe McKinney
Lee Schuster
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
3
Georgia Power Company
Danny Lindsey
Negative
3
3
Georgia System Operations Corporation
Great River Energy
Scott McGough
Brian Glover
Affirmative
Affirmative
3
Gulf Power Company
Paul C Caldwell
Negative
3
3
Hydro One Networks, Inc.
Imperial Irrigation District
David Kiguel
Jesus S. Alcaraz
Affirmative
3
KAMO Electric Cooperative
Theodore J Hilmes
3
3
3
Kissimmee Utility Authority
Kootenai Electric Cooperative
Lakeland Electric
Gregory D Woessner
Dave Kahly
Mace D Hunter
3
Lincoln Electric System
Jason Fortik
Negative
3
Louisville Gas and Electric Co.
Charles A. Freibert
Negative
3
M & A Electric Power Cooperative
Stephen D Pogue
Negative
3
3
Manitoba Hydro
MEAG Power
Greg C. Parent
Roger Brand
3
MidAmerican Energy Co.
Thomas C. Mielnik
Negative
3
Mississippi Power
Jeff Franklin
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
SUPPORTS
THIRD PARTY
COMMENTS (William
Waudby)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
NERC Standards
3
Modesto Irrigation District
Jack W Savage
Negative
3
Muscatine Power & Water
John S Bos
Negative
3
National Grid USA
Brian E Shanahan
Affirmative
3
Nebraska Public Power District
Tony Eddleman
Negative
3
3
New York Power Authority
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power
Cooperative
David R Rivera
Doug White
Affirmative
Affirmative
3
SUPPORTS
THIRD PARTY
COMMENTS (Sacramento
Municipal
Utility District)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NPPD
comments
provided by
Don Schmit.)
Skyler Wiegmann
3
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
3
3
3
3
3
3
3
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Donald Hargrove
David Burke
Ballard K Mutters
John H Hagen
Dan Zollner
Terry L Baker
Thomas G Ward
Mark Yerger
SUPPORTS
THIRD PARTY
COMMENTS (Schmidt,
O'brien,
Moran,
Mackowicz)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
James Leigh-Kendall
Negative
COMMENT
RECEIVED
Ken Dizes
John T. Underhill
James M Poston
Abstain
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
Rutherford EMC
Thomas M Haire
3
Sacramento Municipal Utility District
3
3
3
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
3
Seattle City Light
Dana Wheelock
Negative
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
3
3
3
3
3
Snohomish County PUD No. 1
Southern California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Mark Oens
David B Coher
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Westar Energy
Bo Jones
3
Wisconsin Electric Power Marketing
James R Keller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
NERC Standards
3
Wisconsin Public Service Corp.
Gregory J Le Grave
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
Alabama Municipal Electric Authority
Raymond Phillips
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
4
4
4
4
4
4
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
Buckeye Power, Inc.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Redding
Ronnie Frizzell
Duane S Dahlquist
Manmohan K Sachdeva
Shamus J Gamache
Reza Ebrahimian
Nicholas Zettel
4
City Utilities of Springfield, Missouri
John Allen
4
Constellation Energy Control & Dispatch,
L.L.C.
Margaret Powell
4
Consumers Energy Company
Tracy Goble
4
4
4
4
4
4
4
Cowlitz County PUD
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Rick Syring
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Diana U Torres
Jack Alvey
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
4
Madison Gas and Electric Co.
Joseph DePoorter
Negative
4
Modesto Irrigation District
Spencer Tacke
Negative
Barry R. Lawson
Abstain
4
4
4
4
4
4
Cecil Rhodes
Affirmative
John Lemire
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
John D Martinsen
SUPPORTS
THIRD PARTY
COMMENTS (Tom Breene
for Wisconsin
Public Service
Corp)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
4
Sacramento Municipal Utility District
Mike Ramirez
Negative
4
Seattle City Light
Hao Li
Negative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
Negative
4
Tacoma Public Utilities
Keith Morisette
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
SUPPORTS
THIRD PARTY
COMMENTS (William
Waudby)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Christopher Plante
4
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Integrys Energy Group, Inc.
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
North Carolina Electric Membership Corp.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
COMMENT
RECEIVED
Affirmative
4
4
COMMENTS (See Tom
Breene's
comments WPSC)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy
Comments)
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative,
Inc (SEC))
NERC Standards
4
Utility Services, Inc.
Brian Evans-Mongeon
4
Wisconsin Energy Corp.
Anthony Jankowski
4
WPPI Energy
Todd Komplin
Affirmative
Negative
5
AEP Service Corp.
Brock Ondayko
Negative
5
Amerenue
Sam Dwyer
Negative
5
Arizona Public Service Co.
Scott Takinen
Negative
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Black Hills Corp
Bonneville Power Administration
BP Wind Energy North America Inc
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Buckeye Power, Inc.
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
Brent R Carr
Matthew Pacobit
Clement Ma
George Tatar
Francis J. Halpin
Carla Holly
Shari Heino
Chifong Thomas
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
5
Cleco Power
Stephanie Huffman
5
5
5
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Mike D Hirst
Michael Shultz
Wilket (Jack) Ng
5
Consumers Energy Company
David C Greyerbiehl
5
5
5
5
5
5
5
Bob Essex
Robert Stevens
Tommy Drea
Alexander Eizans
Marcus Ellis
Mike Garton
Dale Q Goodwine
5
Cowlitz County PUD
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Gustavo Estrada
5
Essential Power, LLC
Patrick Brown
5
5
5
5
5
5
5
5
5
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
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
5
SUPPORTS
THIRD PARTY
COMMENTS (We Energies)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
– American
Electric
Power)
SUPPORTS
THIRD PARTY
COMMENTS (Ameren)
SUPPORTS
THIRD PARTY
COMMENTS (Previous
comments
submitted by
AZPS)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (William
Waudby)
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Dana Showalter
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
5
5
Lakeland Electric
Liberty Electric Power LLC
James M Howard
Daniel Duff
Negative
Negative
5
Lincoln Electric System
Dennis Florom
5
5
5
Karin Schweitzer
Rick Terrill
S N Fernando
Affirmative
Affirmative
David Gordon
Affirmative
5
5
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Steven Grego
Neil D Hammer
Abstain
5
Muscatine Power & Water
Mike Avesing
Negative
5
Nebraska Public Power District
Don Schmit
Negative
5
5
5
5
5
5
5
5
5
5
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Pacific Gas and Electric Company
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
David Ramkalawan
Richard J. Padilla
5
Abstain
PacifiCorp
Bonnie Marino-Blair
Negative
5
Pattern Gulf Wind LLC
Grit Schmieder-Copeland
Negative
5
PPL Generation LLC
Annette M Bannon
Negative
5
PSEG Fossil LLC
Tim Kucey
Public Utility District No. 1 of Lewis County
Steven Grega
5
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
5
Sacramento Municipal Utility District
Susan Gill-Zobitz
5
5
Salt River Project
Santee Cooper
William Alkema
Lewis P Pierce
5
5
Seattle City Light
SUPPORTS
THIRD PARTY
COMMENTS (Scott Bos)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (Generator
Forum
Standards
Reveiw Team)
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Kelly
Cumiskey,
PacifiCorp)
SUPPORTS
THIRD PARTY
COMMENTS (North
American
Generator
Form SRT)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (NAGF
Standard's
Review Team)
Michiko Sell
Lynda Kupfer
Michael J. Haynes
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase,
Seattle City
Light)
SUPPORTS
THIRD PARTY
COMMENTS -
NERC Standards
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
5
5
5
Snohomish County PUD No. 1
South Feather Power Project
Southern California Edison Company
Sam Nietfeld
Kathryn Zancanella
Denise Yaffe
Negative
Affirmative
Abstain
5
Southern Company Generation
William D Shultz
Negative
5
5
Tacoma Power
Tennessee Valley Authority
Chris Mattson
David Thompson
Affirmative
Affirmative
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
5
5
U.S. Army Corps of Engineers
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Melissa Kurtz
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
5
Wisconsin Electric Power Co.
Linda Horn
Negative
5
Wisconsin Public Service Corp.
Scott E Johnson
Negative
6
AEP Marketing
Edward P. Cox
Negative
6
APS
Randy A. Young
Negative
6
Arkansas Electric Cooperative Corporation
Keith Sugg
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
6
Cleco Power LLC
Robert Hirchak
6
6
6
6
6
6
6
6
6
6
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
Florida Power & Light Co.
Great River Energy
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Luis Rodriguez
Kevin Querry
Richard L. Montgomery
Silvia P. Mitchell
Donna Stephenson
6
Lincoln Electric System
Eric Ruskamp
6
6
6
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Brenda Hampton
Blair Mukanik
Dennis Kimm
6
Modesto Irrigation District
James McFall
6
6
6
6
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern California Power Agency
John Stolley
Saul Rojas
Matthew Schull
Steve C Hill
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
(Seminole
Electric
Cooperative
Inc.)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Tom Breene
Wisconsin
Public Service
Corp.)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
(AEP))
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Sacramento
Municipal
Utility District)
NERC Standards
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
Oklahoma Gas & Electric Services
Jerry Nottnagel
Abstain
6
PacifiCorp
Kelly Cumiskey
Negative
6
6
6
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Carol Ballantine
Ty Bettis
Stephen C Knapp
Affirmative
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
Public Utility District No. 1 of Chelan County Hugh A. Owen
Abstain
6
Sacramento Municipal Utility District
Diane Enderby
Negative
6
6
Salt River Project
Santee Cooper
Steven J Hulet
Michael Brown
Affirmative
Abstain
6
Seattle City Light
Dennis Sismaet
Negative
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Negative
6
6
Snohomish County PUD No. 1
Southern California Edison Company
Kenn Backholm
Lujuanna Medina
6
Southern Company Generation and Energy
Marketing
6
6
6
6
6
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Peter H Kinney
Affirmative
David Hathaway
Negative
6
Xcel Energy, Inc.
David F Lemmons
Negative
7
7
8
8
9
Alcoa, Inc.
EnerVision, Inc.
Central Lincoln PUD
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
Thomas Gianneschi
Thomas W Siegrist
Edward C Stein
Debra R Warner
Bruce Lovelin
9
Diane J. Barney
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Breene –
Wisconsin
Public Service
Corporation)
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel Energy)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
9
New York State Department of Public Service Thomas G. Dvorsky
10
Florida Reliability Coordinating Council
Linda Campbell
Affirmative
10
Midwest Reliability Organization
Russel Mountjoy
Negative
10
10
10
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
Alan Adamson
Guy V. Zito
Anthony E Jablonski
https://standards.nerc.net/BallotResults.aspx?BallotGUID=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
COMMENT
RECEIVED
Affirmative
Wisconsin Public Service Corp.
Donald Nelson
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group)
Affirmative
6
9
COMMENT
RECEIVED
Affirmative
6
John J. Ciza
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC Standards
10
10
10
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Carter B Edge
Emily Pennel
Donald G Jones
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=361aface-2bfb-4635-9c69-a52f39f94d40[9/6/2013 12:34:33 PM]
Affirmative
Affirmative
Affirmative
Consideration of Comments
Project 2010-17 Definition of Bulk Electric System
The Project 2010-17 Drafting Team thanks all commenters who submitted comments on Draft 2, Phase
2 of the Bulk Electric System definition. The definition was posted for a 30-day formal comment period
from August 6, 2013 through September 4, 2013. Stakeholders were asked to provide feedback on the
definition and associated documents through a special electronic comment form. There were 65 sets
of responses, including comments from approximately 153 different people from approximately 117
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:
Inclusion I4. Based on industry comments, the SDT modified the language of Inclusion I4 to clearly
reflect the SDT’s intent to include individual dispersed power producing units (such as wind and solar
units) that aggregate to greater than 75 MVA , along with the collector system that connects these
units, from the point they aggregate to greater than 75 MVA to the point of connection at 100kV or
higher. While the SDT recognizes that some stakeholders do not agree with the inclusion of individual
dispersed power producing units, FERC Orders 773 and 773-A approved the inclusion of these
individual units. No stakeholder has provided a technical rationale to support removal of the individual
units from the definition. The SDT believes that stakeholder concerns about inclusion of individual units
may be addressed by specifying the Facilities to which an individual standard applies within the
Applicability section of that standard.
The revised language for inclusion I4 now reads:
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Implementation Plan. The SDT received comments by Canadian entities reflecting the fact that there
are varying approaches for making NERC standards effective in North American jurisdictions. NERC
Legal has worked with the Canadian Electricity Association to develop effective date language that
provides for the full range of approaches for making standards effective. This language does not
change the time frame for implementation from the previous posting; it is simply intended to reflect
the differences in regulatory regimes in various jurisdictions. In response to comments and based on
the input from NERC legal, the language in the Implementation Plan was clarified as follows.
This definition shall become effective on the first day of the second calendar quarter after the
date that the definition 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 definition shall become effective on the first day of the first
calendar quarter after the date the definition is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.
White Paper on 50kV threshold: The SDT corrected minor typographical errors in the white paper on
the 50 kV threshold.
Minority issues:
1. Several Canadian entities commented that the 50 kV threshold for loop analysis should not be
applied to Canadian entities due to provincial regulations and because it is action taken to respond to a
FERC directive. The SDT disagrees. Although the project to revise the definition of Bulk Electric System
was undertaken in response to a FERC Order, the SDT believes the threshold in question provides an
appropriate bright-line that supports continent-wide reliability of the BES based on physical principles,
as demonstrated in the technical analysis in the white paper supporting the selection of the 50 kV
threshold. Therefore, the SDT sees no reason for a reference to non-US Registered Entities.
2. Some comments suggested deleting Inclusion I4a concerning the inclusion of individual dispersed
power producing resources. The proposed definition continues to include, through inclusion I4,
individual dispersed power producing resources if those resources aggregate to a total value greater
than 75 MVA. This inclusion treats dispersed power producing resources in a manner that is
comparable to other non-dispersed power producing resources and is an approach that was accepted
and emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options
associated with dispersed power producing resources; however, none of the options explored provided
an equal and effective approach to address the Commission’s reliability concerns with these facilities.
The SDT continues to believe that the best resolution to the industry’s concerns is through clarification
of the applicability of individual Reliability Standards and not a revision to the BES definition. Given
these facts, the SDT is retaining Inclusion I4a but has revised the language of inclusion I4, based on
industry comments, to provide greater clarity of the SDT’s intent.
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,
Consideration of Comments: Project 2010-17 | September 2013
2
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 2010-17 | September 2013
3
Index to Questions, Comments, and Responses
1.
The SDT has separated Inclusion I2 and I4 to provide the clarity requested by the industry in the
first posting comments. In addition, again in response to industry comments, the SDT has added
language to Inclusion I4b to identify the equipment from an ggregation point of greater than 75
MVA to the connection to the BES. Do you agree with these changes? If not, please provide
technical rationale for your disagreement along with suggested language changes. ................... 13
2.
The SDT has proposed an equally effective and efficient alternative to the Commission’s sub-100
kV loop concerns for radial systems by the addition of Note 2 in Exclusion E1 with a threshold
value of 50 kV, and posted a technical rationale to support this threshold. Do you agree with
this threshold? If you do not support this threshold, please provide specific suggestions and
technical rationale in your comments. ........................................................................................... 58
3.
The SDT has added the term ‘Real’ to Exclusion E3b to clarify its intent. Do you agree with this
change? If you do not support this change, please provide specific suggestions and technical
rationale in your comments............................................................................................................ 68
4.
Are there any other concerns with this definition that haven’t been covered in previous
questions and comments? .............................................................................................................. 74
Consideration of Comments: Project 2010-17 | September 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
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC NPCC
10
2.
Greg Campoli
New York Independent System Operator NPCC
2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
4.
Ben Wu
Orange and Rockland Utilities
NPCC
1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
7.
Michael Lombardi
Northeast Power Coordinating Council
NPCC
10
8.
Michael Jones
National Grid
NPCC
1
9.
Mark Kenny
Northeast Utilities
NPCC
1
Hydro One Networks Inc.
NPCC
1
10. David Kiguel
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Christina Koncz
PSEG Power LLC
NPCC
5
12. Helen Lainis
Independent Electricity System Operator NPCC
2
13. Bruce Metruck
New York Power Authority
NPCC
6
14. Randy MacDonald
New Brunswick Power Transmission
NPCC
9
15. Donald Weaver
New Brunswick System Operator
NPCC
2
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. Wayne Sipperly
New York Power Authority
NPCC
5
21. Brian Robinson
Utility Services
NPCC
8
22. Brian Shanahan
National Grid
NPCC
1
2.
Louis Slade
Group
Additional Member
Dominion
Additional Organization
NERC Compliance Policy
RFC
2. Miek Garton
NERC Compliance Policy
NPCC 5, 6
3. Randi Heise
NERC Compliance Policy
MRO
4. Michael Crowley
Electric Transmission Compliance SERC
1, 3
5. William Bigdely
Electric Transmission Planning
SERC
1, 3
6. Craig Crider
Electric Transmission Planning
SERC
1, 3
7. Jeff Bailey
Nuclear
5
8. Chip Humphrey
Power Generation
5
Group
paul haase
3
X
X
X
X
4
5
6
X
X
X
X
7
8
9
10
Region Segment Selection
1. Connie Lowe
3.
2
5, 6
3
seattle city light
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. maike haynes
seattle city light
WECC 5
5. dennis sismaet
seattle city light
WECC 6
4.
Group
Additional Member
Patrick Brown
Additional Organization
NAGF Standards Review Team
X
Region Segment Selection
Consideration of Comments: Project 2010-17 | September 2013
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Allen Schriver
NextEra Energy Resources
5
2.
Steve Berger
PPL Susquehanna, LLC
5
3.
Terry Crawley
Southern Company Generation
5
4.
Pamela Dautel
IPR-GDF Suez Generation NA
5
5.
Dan Duff
Liberty Electric Power
5
6.
Katie Legates
American Electric Power
5
7.
Don Lock
PPL Generation, LLC
5
8.
Chris Schaeffer
Duke Energy
5
9.
Dana Showalter
E.ON Climate & Renewables
5
10. William Shultz
Southern Company
5
11. Mark Young
Tenaska, Inc
5
5.
Brent Ingebrigtson
Group
Additional Member
PPL NERC Registered Affiliates
Additional Organization
Brenda Truhe
PPL Electric Utilities Corporation RFC
1
2.
Annette Bannon
5
PPL Susquehanna, LLC
RFC
3.
PPL Montana, LLC
WECC 5
4.
PPL Generation, LLC
RFC
5
PPL EnergyPlus, LLC
MRO
6
6.
NPCC
6
7.
RFC
6
8.
SERC
6
9.
SPP
6
10.
WECC 6
6.
Elizabeth Davis
Group
Jim Kelley
X
3
X
4
5
X
6
7
8
9
10
X
Region Segment Selection
1.
5.
2
SERC Planning Standards Subcommittee
X
X
Additional Member Additional Organization Region Segment Selection
1. Philip Kleckey
SCE&G
SERC
1, 3, 5, 6
2. John Sullivan
Ameren
SERC
1, 3
3. William Berry
OMU
SERC
3
4. Bob Thomas
IMEA
SERC
4
7.
Group
Additional Member
Robert Rhodes
SPP Standards Review Group
Additional Organization
Consideration of Comments: Project 2010-17 | September 2013
X
Region Segment Selection
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
John Boshears
City Utilities of Springfield
SPP
1, 4
2.
Allan George
Sunflower Electric Power Corporation
SPP
1
3.
Jonathan Hayes
Southwest Power Pool
SPP
2
4.
Tara Lightner
Sunflower Electric Power Corporation
SPP
1
5.
Jerry McVey
Sunflower Electric Power Corporation
SPP
1
6.
James Nail
City of Independence, MO
SPP
3
7.
Kevin Nincehelser
Westar Energy
SPP
1, 3, 5, 6
8.
Valerie Pinamonti
American Electric Power
SPP
1, 3, 5
9.
Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5
10. Sean Simpson
Board of Public Utilities, City of McPherson SPP
NA
11. Don Taylor
Westar Energy
1, 3, 5, 6
12. Mark Wurm
Board of Public Utilities, City of McPherson SPP
8.
Frank Gaffney
Group
SPP
2
3
4
5
6
7
8
9
10
NA
Florida Municipal Power Agency
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. 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
9.
Group
Additional Member
1. Kevin Smith
10.
Group
Additional Member
Joe Tarantino
BANC & SMUD
Additional Organization
Region Segment Selection
Balancing Authority Northern California WECC 1
Jamison Dye
Additional Organization
Bonneville Power Administration
Region Segment Selection
1. Lorissa Jones
Transmission Reliability Program WECC 1
2. John Anasis
Technical Operations
WECC 1
3. Berhanu Tesema
Transmission Planning
WECC 1
4. Chuck Matthews
Transmission Planning
WECC 1
11.
Group
Colby Bellville
Duke Energy
Consideration of Comments: Project 2010-17 | September 2013
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
12.
Group
Associated Electric Cooperative, Inc. JRO00088
David Dockery
Additional Member
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
Group
Ben Engelby
Additional
Member
X
X
X
ACES Standards Collaborators
Additional Organization
Region
Segment
Selection
1. John Shaver
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.
WECC 1, 4, 5
2. Shari Heino
Brazos Electric Power Cooperative, Inc.
ERCOT 1, 5
3. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
4. Bob Solomon
Hoosier Energy Rural Electric Cooperative, Inc.
RFC
1
5. Mark Ringhausen
Old Dominion Electric Cooperative
SERC
3, 4
6. Bill Hutchison
Southern Illinois Power Cooperative
SERC
1
7. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
14.
Individual
Ashley Stringer
Oklahoma Municipal Power Authority
15.
Individual
Southwest Power Pool Regional Entity
Individual
Emily Pennel
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
17.
Individual
Bob Steiger
18.
Individual
William Gallagher
16.
X
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
13.
X
X
X
X
X
X
X
Salt River Project
X
X
X
X
Transmission Access Policy Study Group
X
X
X
X
Consideration of Comments: Project 2010-17 | September 2013
X
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
Individual
Wayne Johnson
Southern Company
X
X
X
X
Individual
21. Individual
Kelly Cumiskey
Thomas Breene
PacifiCorp
Wisconsin Public Service Corporation
X
X
X
X
22.
Individual
Joseph DePoorter
Madison Gas and Electric Company
23.
Individual
David Thorne
Pepco Holdings Inc
24.
Individual
Scott Bos
25.
Individual
26.
19.
20.
X
X
X
X
X
X
X
X
X
X
Muscatine Power and Water
X
X
X
X
John Seelke
Public Service Enterprise Group
X
X
X
Individual
Scott Berry
Indiana Municipal Power Agency
27.
Individual
Barbara Kedrowski
Wisconsin Electric Power Company
28.
Individual
John Bee
Exelon and its' affiliates
29.
Individual
Illinois Municipal Electric Agency
Individual
Bob Thomas
Gary Kruempel, Terry
Harbour, Tom Mielnik
Shaun Moran, Lynn
Schmidt, Joe O'Brien,
Ed Mackowicz,
32.
Individual
Michael Falvo
Independent Electricity System Operator
33.
Individual
David Jendras
Ameren
34.
Individual
Chifong Thomas
BrightSource Energy, Inc.
35.
Individual
Amber Anderson
East Kentucky Power Cooperative
X
X
X
Individual
37. Individual
Thomas Foltz
William Waudby
American Electric Power
Consumers Energy Company
X
X
X
38.
Individual
Kenneth A Goldsmith
Alliant Energy
39.
Individual
Nazra Gladu
Manitoba Hydro
X
40.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
X
41.
Individual
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
42.
Individual
Don Schmit
Nebraska Public Power District
X
X
X
30.
Individual
31.
36.
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
MidAmerican Energy Company
NIPSCO
Consideration of Comments: Project 2010-17 | September 2013
X
X
X
X
X
X
X
X
X
X
X
X
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
43.
Individual
2
3
4
5
Lakeland Electric
Individual
45. Individual
Bret Galbraith
Wayne Sipperly
Seminole Electric Cooperative, Inc.
New York Power Authority
46.
Individual
Mahmood Safi
Omaha Public Power District
47.
Individual
Don Streebel
Idaho Power Company
48.
Individual
Diane Barney
Individual
Thomas Dvorsky
NARUC
New York State Department of Public
Service
50.
Individual
Patrick Farrell
Southern California Edison Company
X
51.
Individual
Scott Langston
City of Tallahassee
X
52.
Individual
Oliver Burke
Entergy Services, Inc.
X
53.
Individual
Terry Volkmann
X
X
X
Individual
Ryan Walter
Volkmann Consulting, Inc
Tri-State Generation and Transmission
Association, Inc.
55.
Individual
Alice Ireland
Xcel Energy
X
X
X
56.
Individual
MRO
Individual
Russel Mountjoy
David Kiguel (by
Ayesha Sabouba)
58.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
59.
Individual
John Robertson
First WInd
X
60.
Individual
Anthony Jablonski
ReliabilityFirst
61.
Individual
Michael Goggin
American Wind Energy Association
Individual
63. Individual
Dan Inman
Richard Vine
Minnkota Power Cooperative
California Independent System Operator
64.
Spencer Tacke
Modesto Irrigation District
Public Utility District No.1 of Snohomish
County
49.
54.
57.
62.
65.
Individual
Individual
Kenn Backholm
7
8
9
10
X
Larry Watt
44.
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Hydro One
Consideration of Comments: Project 2010-17 | September 2013
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
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).
Summary Consideration: The SDT thanks you for following the guidelines and will consider your comments as supporting the positions
of the entities shown here.
Organization
Supporting Comments of “Entity Name”
Lakeland Electric
Lakeland Electric supports the Florida Municipal Power Agency comments.
New York Power Authority
LPPC
seattle city light
Sacramento Municipal Utility District (SMUD)
Entergy Services, Inc.
SERC OC Review Group comments
Oklahoma Municipal Power Authority
Transmission Access Policy Study (TAPS) Group
Illinois Municipal Electric Agency
Transmission Access Policy Study Group (TAPS) and SERC OC Review Group
Consideration of Comments: Project 2010-17 | September 2013
12
1. The SDT has separated Inclusion I2 and I4 to provide the clarity requested by the industry in the first posting comments. In
addition, again in response to industry comments, the SDT has added language to Inclusion I4b to identify the equipment from an
aggregation point of greater than 75 MVA to the connection to the BES. Do you agree with these changes? If not, please provide
technical rationale for your disagreement along with suggested language changes.
Summary Consideration: The proposed definition continues to include individual dispersed power producing resources, through
Inclusion I4, if those resources aggregate to a total value greater than 75 MVA. Inclusion I4 treats dispersed power producing resources
in a manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns about inclusion
of individual dispersed power-producing units is through clarification of the applicability of individual Reliability Standards and not a
revision to the BES definition. Given these facts, the SDT is retaining Inclusion I4a but has revised the language of inclusion I4, based on
industry comments, to provide greater clarity of the SDT’s intent. The revised language is as follows:
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to
greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.
Organization
Yes or No
NAGF Standards Review Team
No
Consideration of Comments: Project 2010-17 | September 2013
Question 1 Comment
1. Replace the current ballot’s draft I4 language:”I4 - Dispersed power producing
resources consisting of: a) Individual resources that aggregate to a total capacity
greater than 75 MVA (gross nameplate rating), and b) The system designed
primarily for delivering capacity from the point where those resources aggregate
to greater than 75 MVA to a common point of connection at a voltage of 100 kV or
13
Organization
Yes or No
Question 1 Comment
above.”With the proposed comment I4 language:”I4 - Dispersed power producing
resource projects, or portion(s) thereof, designed primarily for supplying
wholesale power (e.g., a wind farm, or solar farm) that aggregate to a total
capacity greater than 75 MVA (gross nameplate rating) at a common point of
connection to a voltage of 100 kV or above consisting of: a) The individual
resources, and b) The delivery system designed primarily for delivering capacity
from i) the point where those resources aggregate to the total connected
capacity; to ii) a common point of connection at a voltage of 100 kV or above.”
Rationale: o “projects ... designed primarily for wholesale” - nothing in this posted
version distinguishes between generation for retail (behind the meter) and
generation for wholesale. As such rooftop PVs, generator assistance programs, or
other similar small power-producing incentives, might be otherwise interpreted as
included under I4.
o “(e.g., a wind farm, or solar farm)” - Because the SDT’s I4 text-box will be
dropped from the final version, we believe this inclusion is necessary to retain an
illustration of the intent.
o I4.a - While imposing BES Standards of governance toward management of
individual small units is counter-productive and administratively burdensome, we
do agree that differentiating applicability to various Standards should be specified
through those Standards. To that end, we are dedicated to drafting and
vigorously promoting a SAR to appropriately address dispersed power producing
resource applicability within individual NERC Standards. In keeping with that
commitment it is suggested that I4a be deleted from the BES definition. This
would avoid temporarily imposing inappropriate requirements that would later
have to be eliminated by modification of individual standard requirements. A
better approach would be to add requirements where needed for individual small
Consideration of Comments: Project 2010-17 | September 2013
14
Organization
Yes or No
Question 1 Comment
units.
o I4.b - We believe our proposed wording: o Appropriately addresses impact to
BES reliability. Rather than offering some illusion for reliability at a lesser impact
level, this proposal recognizes that reliability rests in TPs, BAs, RCs, and TOPs
responsibly addressing the single greatest contingency arising from, and the
behavior of, dispersed power producing resources in the aggregate. Enforcing
governance for management to any lesser level is not productive and has no true
value to BES reliability.
o Better aligns with FERC’s Determination within Order 770 paragraph 114.
o Aligns with FERC’s Determination for I2 within Order 773 paragraph 91.
o Aligns with FERC’s Determination for I2 within Order 773 paragraph 92.
Associated Electric Cooperative, Inc. No
- JRO00088
Consideration of Comments: Project 2010-17 | September 2013
FOR: Inclusion I4REPLACE: Complete wording of I4WITH: “I4 - Dispersed power
producing resource projects , or portion(s) thereof, designed primarily for
supplying wholesale power (e.g., a wind farm, or solar farm) that aggregate to a
total capacity greater than 75 MVA (gross nameplate rating) at a common point of
connection to a voltage of 100 kV or above consisting of:a) The individual
resources, and b) The delivery system designed primarily for delivering capacity
from i) the point where those resources aggregate to the total connected
capacity; to ii) a common point of connection at a voltage of 100 kV or
above.”RATIONALE: (1) o “projects ... designed primarily for wholesale” - nothing
in this posted version distinguishes between generation for retail (behind the
meter) and generation for wholesale. As such roof-top PVs, generator assistance
programs, or other similar small power-producing incentives, might be otherwise
15
Organization
Yes or No
Question 1 Comment
interpreted as included under I4. (2) o “(e.g., a wind farm, or solar farm)” Because the SDT’s I4 text-box will be dropped from the final version, we believe
this inclusion is necessary to retain an illustration of the intent. (3) o I4.a - While
imposing BES Standards of governance toward management of individual small
units is counter-productive and administratively burdensome, we do agree that
differentiating applicability to various Standards should be specified through those
Standards. To that end, we are dedicated to drafting and vigorously promoting a
SAR to appropriately address dispersed power producing resource applicability
within individual NERC Standards. (4) o I4.b - We believe our proposed wording:o
Appropriately addresses impact to BES reliability. Rather than offering some
illusion for reliability at a lesser impact level, this proposal recognizes that
reliability rests in TPs, BAs, RCs, and TOPs responsibly addressing the single
greatest contingency arising from, and the behavior of, dispersed power
producing resources in the aggregate. Enforcing governance for management to
any lesser level is not productive and has no true value to BES reliability.o Better
aligns with FERC’s Determination within Order 770 paragraph 114.o Aligns with
FERC’s Determination for I2 within Order 773 paragraph 91.o Aligns with FERC’s
Determination for I2 within Order 773 paragraph 92.
ALTERNATE APPROACH:In the consideration of comments, the drafting team
indicated that a SAR might be submitted to appropriately adjust GO and GOP
standards requirements for dispersed generating facilities. We agree that is the
approach to undertake. In order to support this approach, I4 should be deleted to
avoid the situation where inappropriate provisions could become effective and
compliance become difficult or impossible for entities until work is completed
through the SAR to adjust those requirements. In the filing with FERC this
procedure could be explained so that FERC can be assured that their approval of
inclusion of dispersed generating facilities in the phase I order will be
appropriately implemented. AECI also supports NAGF's recommendation for the
Consideration of Comments: Project 2010-17 | September 2013
16
Organization
Yes or No
Question 1 Comment
SDT with regard to I2 changes.
Response: The SDT does not believe introducing the term ‘wholesale’ into the definition provides any additional clarity. No change
made.
The proposed Inclusion I4 treats dispersed power producing resources comparably to the non-dispersed power producing resources
in Inclusion I2 and is consistent with the established values shown in the Statement of Compliance Registry Criteria. The threshold
values shown have been accepted by the Commission and endorsed by the Planning Committee. No change made.
American Electric Power
No
AEP does not agree with the premise that BES elements (measured for
compliance) should be as granular as the individual dispersed power resource.
We do not see the reliability benefit of tracking all of the compliance elements for
individual wind turbines when the focus should be placed on the aggregate of the
facilities. Does the RC want to be notified of an outage of each individual wind
turbine in real-time, or a loss of significant portion of the wind farm? If we are not
careful, we will have entities at these resources and others monitoring them (BAs,
TOPs, RCs) focusing on minor issues that will distract from more relevant reliability
needs. We believe it would be beneficial and provide more clarity if the verbiage
“aggregate to a total capacity greater than 75 MVA (gross nameplate rating) at a
common point of connection to a voltage of 100 kV or above” were moved to the
beginning of the I4 paragraph rather than as a sub-bullet. For example, “Dispersed
power producing resources that aggregate to a total capacity greater than 75
MVA....”.We appreciated the development of the diagram to explain the scenario.
We encourage the team to continue to provide these illustrations to clarify the
intent and the application.
Alliant Energy
No
Alliant Energy agrees with the changes to I2 and I4b, however, firmly believe I4a
must be deleted. There is no way an individual dispersed generator in the range
Consideration of Comments: Project 2010-17 | September 2013
17
Organization
Yes or No
Question 1 Comment
of <1 MW to 5 MW will have any reliability impact on the reliability of the BES. In
addition, in the MRO footprint alone there would be ~7500 generators added to
the list of BES equipment, which would be extremely costly to manage from both
the Registered Entity and Regional Entity's perspective.
Lincoln Electric System
No
Although appreciative of the drafting team’s efforts, LES is concerned with the
proposed inclusion of the individual dispersed power producing resources as part
of the Bulk Electric System versus the point at which the resources aggregate to a
capacity greater than 75MVA. As currently proposed, the burden would be on the
registered entities to either seek multiple exclusions through the BES Exception
Process or else race to add numerous BES Elements to existing programs,
processes and maintenance schedules to ensure compliance with Reliability
Standards such as PRC-005-1.1b, PRC-004-2a, FAC-001, etc. To prevent broad
sweeping changes to existing compliance requirements without sufficient
technical justification, LES recommends Inclusion I4a be removed altogether and
I4b be retained. In the event a reliability-related need is identified in the future
pertaining to the individual resources, LES suggests that revisions be made to
those standards deemed applicable.
American Transmission Company,
LLC
No
ATC appreciates the changes the SDT made to I4, however, believe the wording
of I4a still does not adequately communicate the desired treatment of small
dispersed power producing resources as an aggregate, rather than an individual
basis, when the aggregate capacity is 75 MVA or more. To address this issue, we
suggest the following wording change to I4a, “Aggregate of dispersed resources
when they aggregate to a total capacity of greater than 75 MVA (gross nameplate
rating, and”
Consideration of Comments: Project 2010-17 | September 2013
18
Organization
Yes or No
Minnkota Power Cooperative
No
Question 1 Comment
During the 8/21/2013 webinar the presenter emphasized the critical nature of the
aggregate generation of dispersed power producing resources to the reliability of
the interconnected transmission system. I4 subpart (a) is inconsistent with the
stated critical nature of the aggregate generation.
The presenter also indicated that standards that apply to GO/GOP associated
standards should be addressed via a SAR to correct reliability standards that
impose a burden on the industry without providing a significant benefit to
reliability. The appropriate manner to address this discrepancy is not to submit a
SAR to modify the standards that would inappropriately invoke requirements on
individual generators due to their inclusion in the BES definition, but to eliminate
I4 subpart (a) and modify standards in the future to address any reliability issues
that may need the imposition of requirements for individual dispersed power
producing resources. The following language is suggested for a revised I4:I4 Dispersed power producing resources consisting of the system designed primarily
for delivering capacity from the point where those resources aggregate to greater
than 75 MVA to a common point of connection at a voltage of 100 kV or above.
Proceeding in this manner will avoid temporary inappropriate standards
requirements being applied to individual dispersed power resources and still
address the individual resources in standards where needed to support reliability.
First WInd
No
Consideration of Comments: Project 2010-17 | September 2013
First Wind supports the separation of I2 and I4 and the 75 MVA threshold for
aggregating facilities in Inclusion I4 (b), and the exclusion of collector system
components that aggregate less than 75 MVA of generation, First Wind disagrees
with the inclusion of small individual dispersed generators per Inclusion I4 (a). This
problem can be resolved by either removing I4 (a) in its entirety or revising it to
clarify that the only BES-relevant standards that apply to individual dispersed
19
Organization
Yes or No
Question 1 Comment
generators are those that affirmatively state that they apply to dispersed
generators. While individual generators were included in the Phase I BES
definition, Phase II of this project provides an opportunity to refine and improve
the BES definition such that industry compliance efforts are focused on activities
that will truly have a beneficial impact on reliability. Including individual dispersed
generators in the BES definition will cause a major diversion away from efforts
that improve BES reliability, as entities are forced to simultaneously seek relief via
the Exception Process to exclude individual dispersed generators that are
insignificant from a reliability standpoint from their programs while at the same
time attempting to modify their existing compliance programs to accommodate
individual dispersed generators in the event that the exception applications are
not approved. Regions will be faced with a huge backlog of exception requests for
small distributed generators while Generator Owners with dispersed generating
assets struggle to implement reliability standards that were never drafted with the
intent of being applicable to anything but large scale generating stations. As a
result, proceeding with the BES definition as currently drafted would actually
impair, rather than improve, bulk electric system reliability. First Wind supports
the exclusion of collector system components that aggregate less than 75 MVA, it
seems inconsistent that a 1-2 MVA individual dispersed generator is deemed
significant to reliability but the equipment that is utilized to connect multiple
dispersed generators totaling up to 75 MVA is deemed not significant to reliability.
The logic that led to the exclusion of collector system equipment that aggregates
less than 75 MVA, as well as the logic expressed on the webinar that 75 MVA is
the threshold at which the loss of generation could have an impact on BES
reliability, argues for also excluding individual dispersed generators. Furthermore,
what is the logic of including individual 1-2 MVA wind turbine generator at a >75
MVA wind farm while excluding an individual wind turbine at a <75 MVA wind
farm? With no technical rationale or difference in effects on BES reliability, how
can identical 2 MVA units be treated so differently? The only compelling reason
Consideration of Comments: Project 2010-17 | September 2013
20
Organization
Yes or No
Question 1 Comment
for applying BES standards to individual dispersed generators would be if there
were a real risk of a common mode failure affecting a large share of the dispersed
generators in a >75 MVA wind plant. However, per FERC Order 661A, wind turbine
generators already comply with voltage and frequency ride-through standards
that are far more stringent than those apply to other types of generators. As a
result, if a common mode failure caused by a grid disturbance were to affect the
wind turbines in a >75 MVA wind plant, the impact on the wind plant would be
irrelevant for grid reliability because the voltage and/or frequency deviation
would have already caused most if not all of the conventional generators in the
grid operating area to trip offline. No compelling rationale has been offered for
why including individual dispersed wind turbine generators in the BES definition
will improve grid reliability.
Florida Municipal Power Agency
No
Consideration of Comments: Project 2010-17 | September 2013
FMPA thanks the SDT for its efforts. Although FMPA agrees with separating I4
from I2, we believe the SDT made a grammatical / logical error in the new I4.
Inclusion I4 as posted reads: I4 - Dispersed power producing resources consisting
of:a) Individual resources that aggregate to a total capacity greater than 75 MVA
(gross nameplate rating), and b) The system designed primarily for delivering
capacity from the point where those resources aggregate to greater than 75 MVA
to a common point of connection at a voltage of 100 kV or above. The logical
structure of I4 a) and I4 b) read literally does not reflect the intent of the SDT. The
SDT seems to want to both: i) Identify the intersection of bullet a) and bullet b)
[e.g., only a) vehicles with b) more than 2 axels need to be weighed at a truck
stop, e.g., the subset of a) vehicles and b) with more than two axels]ii) While at
the same time describe what is part of the BES [e.g., a pie is made of a) filling and
b) crust, e.g., the addition of a) and b)]. The use of “and” at the end of bullet a)
read literally would be interpreted as adding a) and b), i.e., a pie being made of
filling and crust, and does not limit the scope to the intersection of bullets a) and
21
Organization
Yes or No
Question 1 Comment
b). That is, the BES pie is made of individual resources that aggregate to > 75 MVA
with no criteria over which that aggregation is performed (is it service territory,
geography, within a fence, etc.) and b) the portion of a collector system that
carries > 75 MVA in aggregation. The word “and” cannot perform both functions
of adding a)+b) while at the same time identifying the intersecting subset of set a)
and set b), which is what the SDT seems to be attempting to do. What the team
must have meant was:I4 - Dispersed power producing resources that aggregate to
a total capacity greater than 75 MVA (gross nameplate rating), and that are
connected through a system designed primarily for delivering such capacity from
the point at which those resources aggregate to greater than 75 MVA to a
common point of connection at a voltage of 100 kV or above. The BES portion of
such resources includes: a) The individual resources, and b) The system designed
primarily for delivering capacity from the point where those resources aggregate
to greater than 75 MVA to a common point of connection at a voltage of 100 kV or
above. This intent is reflected in the diagram provided by the SDT in the comment
form. This grammatical / logic error almost caused FMPA to vote Negative. The
version of I4 posted read literally, an auditor does not know on what basis the 75
MVA of generation would be integrated, e.g., over the service territory of the
entity? The auditor also is uninformed of whether this includes behind the meter
generation or not. FMPA implores the SDT to correct this grammatical / logical
error. If this error is not corrected, we will likely be changing our vote, and making
recommendations to vote Negative on recirculation / final ballot.
Indiana Municipal Power Agency
No
Consideration of Comments: Project 2010-17 | September 2013
For question 1, Indiana Municipal Power Agency agrees with the comments
submitted by Frank Gaffney, Floriday Municipal Power Agency.
22
Organization
Yes or No
California Independent System
Operator
No
Consideration of Comments: Project 2010-17 | September 2013
Question 1 Comment
It is clear that the SDT has taken significant action to distinguish between
dispersed power producing resources and traditional generating resources
through modification of inclusion I4. However, the California ISO is concerned
that the new verbiage under I4 a), as well as the color-coded diagram included on
the comment form to provide clarification of BES elements, actually results in
ambiguity as to whether each individual power producing resource must be
treated as a BES Element. In particular, use of the phrase “Individual resources
that aggregate...” under I4 a), along with use of the word “and” between I4 a) and
I4 b), leaves open to interpretation whether each individual power producing
resource (e.g., each wind turbine within a wind farm that aggregates to greater
than 75 MVA) must be treated as a BES element or whether only the aggregated
whole is a BES element. Though it may be that the SDT meant to capture that the
combination of all aggregated resources and the delivery system together
comprise a BES element, it could be construed that each individual resource under
a) is a BES element and the system for delivering capacity referred to under b) is a
BES element. This is further confused by the drawing included on the comment
form which uses a blue color to identify each individual power producing resource
and uses the same blue color to identify the system for delivering capacity. The
legend in the comment box above this drawing states “Green identifies non-BES
portions of the Collector System. Blue identifies the dispersed power producing
resources and BES Elements.” The ISO is concerned that this ambiguity may
create uncertainty regarding whether particular Reliability Standard requirements
apply only to the aggregated resource as a whole or to the individual power
producing resources that comprise the aggregated resource, which is a matter
that is better addressed on a Standard-specific basis. In light of this ambiguity, the
ISO is abstaining and recommends that the SDT clarify its definition so that the
focus is on aggregated resource rather than the individual components.
23
Organization
Yes or No
Madison Gas and Electric Company
No
Consideration of Comments: Project 2010-17 | September 2013
Question 1 Comment
MG&E is voting against the BES Phase II definition due to the fact that it contains
Inclusion (I) 4a; Individual resources that aggregate to a total capacity greater than
75 MVA (gross nameplate rating). MG&E recommends that I4a be removed and
I4b be maintained as the point of aggregation is what is modeled and makes the
most sense. Recommend I4 to read as: “Dispersed power producing resources
consisting of the system designed primarily for delivering capacity from the point
where those resources aggregate to greater than 75 MVA to a common point of
connection at a voltage of 100 kV or above”. Please see the following reasons for
our negative vote: 1. An individual 1.5 mW wind turbine does not impact the BES
when it reduces its output (remember just because a turbine is rated at 1.5mW
doesn't mean it automatically reaches that output when the wind blows) or trips
offline. Entities have been making comments that the place where power is
aggregated (usually the bus) should be included and not individual wind turbines,
solar collectors, manure digesters, etc (as shown in the comment form). The
amount of compliance time for PRC-004 would never be completed. Wind
turbines have up to 250 plus reasons why they can trip. Usually due to the change
in wind direction. If the wind changes direction and the turbine head cannot keep
up within a certain degree of angle, the unit will trip. Coming back on line when
the angle requirements are met. So, Entity's will need to apply the R2 of PRC-0042a, for every wind turbine trip. We do not have the resources to review these trips
and that 1.5 wind turbine does not impact the BES. We will agree that the point of
interconnection (of greater than 75 MVA) is important and should be contained in
the BES definition as written in I4B. PRC-004-2a is only one Standard,
notwithstanding; BAL-001-TRE-01, FAC-001, FAC-003, FAC-008-3, MOD-024, MOD025, MOD-026, MOD-027, PRC-005, PRC-006-SPP-01, PRC-019, PRC-024, PRC-025,
and TOP-003. A 75 MVA wind farm is not equal to a 75 MVA combustion turbine.
Yes, energy flow is modeled the same (at full name plate output) but these two
extremely different facilities are quite different. The wind facility is not
24
Organization
Yes or No
Question 1 Comment
dispatchable (only reduction in Mw output can take place when there is an
output) and wind facilities usually are set at a constant power factor and do not
adjust for frequency deviations.2. The SDT has recommended that a SAR be
submitted in order to refine the Standards that would be applicable to individual
power producing resources contained under I4 of the phase II definition. This
response is not acceptable. The SDT should not passively answer an entity's
question by stating that a different process "may" fix the issue at hand.
Recommend I4a be deleted and I4b be maintained as I4a. During the 8/21/2013
webinar the presenter emphasized the critical nature of the aggregate generation
of dispersed power producing resources to the reliability of the interconnected
transmission system. I4 subpart (a) is inconsistent with the stated critical nature of
the aggregate generation. The presenter also indicated that standards that apply
to GO/GOP associated standards should be addressed via a SAR to correct
reliability standards that impose a burden on the industry without providing a
significant benefit to reliability. The appropriate manner to address this
discrepancy is not to submit a SAR to modify the standards that would
inappropriately invoke requirements on individual generators due to their
inclusion in the BES definition, but to eliminate I4 subpart (a) and modify
standards in the future to address any reliability issues that may need the
imposition of requirements for individual dispersed power producing resources.
Please Note that FAC-001 and FAC-002 have established processes for generators
(of all shapes and sizes) to interconnect to the BES.3. I4a should be deleted in its
entirety. The SDT is forcing every dispersed power Facility over 75 MVA to be in
the definition, where the SDT should be keeping individual resources out and
allow other Standards and SDTs to determine if that should be included within
each individual Standard. The BES definition should be written to give broad
details and each individual Standard should be where details are maintained. This
is already the case for the following Standards; MOD-025-1, R1 and VAR-001-2, R3
are two examples where the Standard dictates what is applicable and what is not.
Consideration of Comments: Project 2010-17 | September 2013
25
Organization
Yes or No
Question 1 Comment
4. We do not believe that since FERC has approved Phase I that the SDT is bound
by that approval as being unchangeable. The Commission has only approved a
part of the process and nowhere is it stated that once Phase I is approved that it
cannot be changed. This is proof with the other changes that the SDT has made in
Phase II compared to Phase I. 5. NERC or the SDT have not provided the industry
with event analysis or lessons learned information that an individual dispersed
power producing resource (not whole facilities) within a Facility has led to
instability of the BES. 6. The inclusion of I4a does not alien itself with the current
NERC and Regional RAI process. NERC's CEO and President has said that
everything cannot be a priority. The amount of records management will only
benefit a company who sells their services in managing individual power
producing resources (i.e. paper work). The Registered entity and their Region will
not see the benefit of tracking several thousand wind turbines and solar panels,
for what? The "what" is unknown because the SDT is taking words of the
"Statement of Compliance Registry Criteria" and applying it to our standards
development process. Currently Entities do not register per Facility, but this
definition does force entities to register per Facility. The SDT is mixing apples and
oranges.7. The BES SDT has stated that the collector system is not included within
the definition. But, FAC-008-3, is written to support the reliability of the BES and
Requirement 2 states that each Generator Owner shall have a documented
methodology between the generator (R1) to the point of interconnection. This
means that the collector system is part of the BES definition. Please clarify how
one standard pulls in the collector system and the proposed definition keeps it
out? The removal of I4a will solve this issue. If individual resources need to be in
based on system instability issues, then this can be addressed at a later date, once
it is proven that individual resources need to be considered part of the BES and
the individual resources cause BES instability.
Consideration of Comments: Project 2010-17 | September 2013
26
Organization
Yes or No
Muscatine Power and Water
No
MP&W appreciates the changes SDT made to I4. However, we think that the
wording of I4a still does not adequately communication that desired treatment of
small dispersed power producing resources as an aggregate, rather than on an
individual basis, when the aggregate capacity is 75 MVA or more. To address this
issue, we suggest the following wording change to I4a, “Aggregation point of
dispersed resources when they aggregate to a total capacity of greater than 75
MVA (gross nameplate rating, and”An individual 1.5 MW wind turbine does not
impact the BES when it reduces its output (remember just because a turbine is
rated at 1.5 MW doesn't mean it automatically reaches that output when the
wind blows) or trips offline. Entities have been making comments that the place
where power is aggregated (usually the bus) should be included and not individual
the wind turbines, solar collectors, manure digesters, etc. The amount of
compliance time for PRC-004 would never be enough. Wind turbines have up to
250 plus reasons why they can trip. Usually due to the change in wind direction.
If the wind changes direction and the turbine head can not keep up within a
certain degree of angle, the unit will trip. Coming back on line when the angle
requirement is met. So, Entity's will need to apply the R2 of PRC-004-2a, for every
wind turbine trip. Not all Entities have the resources to review these trips and
that 1.5 MW wind turbine does not impact the BES. MP&W beleives that the
point of interconnection (of greater than 75 MVA) is important and should be
contained in the BES definition as written in I4B. PRC-004-2a is only one Standard,
notwithstanding; BAL-001-TRE-01, FAC-001, FAC-003, MOD-024, MOD-025, MOD026, MOD-027, PRC-005, PRC-006-SPP-01, PRC-019, PRC-024, PRC-025, and TOP003.
MRO
No
MRO recommends the removal of I4 a) and 14b Industry requested the point of
aggregation to be added in place of the individual generators themselves, not as
Consideration of Comments: Project 2010-17 | September 2013
Question 1 Comment
27
Organization
Yes or No
Question 1 Comment
well. The inclusion of this statement, I4 b, tends to lead industry to believe the
individual generators will still remain under the new definition of the BES in
addition to the aggregation point. The addition of individual resources which are
not material to the BES creates undue burden on the registered entities and
regional entities through the process of identifying these assets in order to have
to apply for an exception due to these assets not being material to the BES.
Proposed re-write of I4: Aggregate point where dispersed power producing
resources aggregate at a common bus to a total capacity greater than 75 MVA
(gross name plate rating) linking to a common point of connection at a voltage of
100kV or above.
BrightSource Energy, Inc.
No
No. We agree with the separation of I2 and I4 and this does provide clarity by
creating a distinction between more traditional generation and distributed
generation resources. We disagree with I4 to be applied only when both (A) and
(B) are true. We recognize that each single small generator or even a group of
these small generators cannot impact the BES and therefore, we would support
the including only of the individual generating resources (A) (i.e., greater than 75
MVA) in the definition. The inclusion of the aggregate point (B) below 100 kV will
improve reliability by focusing on the area that can cause the loss of 75MVA of
distributed generation resources. We recognize that there will be complication in
determining the aggregate point and to the implementation of standards
associated with this portion of the collector system. For example, the various
standards that are associated with the BES definition will also need to apply to this
portion of the collector system and associated low voltage equipment.
Omaha Public Power District
No
Omaha Public Power District (OPPD) agrees and appreciates the SDT’s efforts to
provide clarity by separating dispersed power producing resources from Inclusion
Consideration of Comments: Project 2010-17 | September 2013
28
Organization
Yes or No
Question 1 Comment
I2 and returned to its own separate Inclusion I4. However, OPPD is still concerned
with the Inclusion I4a that includes the individual generator as part of BES.
Where, the Inclusion I4b clearly and correctly recognizes the aggregate point to be
identified as a BES facility. We agree that the aggregation point (or bus) should be
part of the BES, if the total aggregated generation is at 75 MVA or higher, as
stated in the Inclusion I4b. OPPD believes that the individual unit by itself can’t
impact the reliability of BES. On the other hand, the compliance responsibilities
that go along with are burdensome with no benefit to the reliability of the BES.
Therefore, OPPD suggests consider removing Inclusion I4a from the BES Definition
Inclusions. We strongly believe that I4b is completely addressing the dispersed
power producing resources inclusion into BES. Additionally, OPPD supports
comments provided by Madison Gas & Electric (MG&E).
Public Utility District No.1 of
Snohomish County
No
Consideration of Comments: Project 2010-17 | September 2013
Snohomish supports the Project 2010-17 - Definition of the BES (Phase 2)
Standard Drafting Team in its efforts to clarify the BES definition. Although
Snohomish supports the current definition and will be voting affirmative, we are
concerned with the compliance burden to small dispersed generators that
typically are less than 2 MW and have capacity factors in the 25 to 35% range, and
may be inclined to change our position if the following issues are not resolved.
Snohomish believes these concerns can be addressed within the Reliability
Standards applicable to GO/GOPs or with the suggested changes
below”.1.Replace the current ballot’s draft I4 language:”I4 - Dispersed power
producing resources consisting of:a) Individual resources that aggregate to a total
capacity greater than 75 MVA (gross nameplate rating), and b) The system
designed primarily for delivering capacity from the point where those resources
aggregate to greater than 75 MVA to a common point of connection at a voltage
of 100 kV or above.”With the proposed comment I4 language:”I4 - Dispersed
power producing resource projects , or portion(s) thereof, designed primarily for
29
Organization
Yes or No
Question 1 Comment
supplying wholesale power (e.g., a wind farm, or solar farm) that aggregate to a
total capacity greater than 75 MVA (gross nameplate rating) at a common point of
connection to a voltage of 100 kV or above consisting of:a) The individual
resources, andb) The delivery system designed primarily for delivering capacity
from i) the point where those resources aggregate with a total connected capacity
greater than 75MVA; to ii) a common point of connection at a voltage of 100 kV or
above.”Rationale:”projects ... designed primarily for wholesale” - nothing in the
currently posted version of Inclusion I4 distinguishes between generation for retail
(behind the meter) and generation for wholesale. As such roof-top PVs, generator
assistance programs, or other similar small power-producing incentives, might be
otherwise interpreted as included under I4. There is a real possibility that, with
net metering laws, tax incentives, and related public policies strongly favoring the
development of, for example, small, individually-owned solar PV systems, those
small systems could easily exceed the 75 MVA thresholds in the aggregate.
Considered individually, these small systems have no discernible impact on the
reliable operation of the BES. With sufficient market penetration, these systems
might conceivably have some impact on the BES, but mediating that impact
should be the responsibility of TPs, BAs, TOPs, and other system operators. The
regulatory burden imposed on small owners of individual distributed generation
systems that would result from classifying such small generators as part of the BES
would be significant, and a strong disincentive running contrary to current public
policy favoring such systems. Yet, because such small systems have no impact on
the reliable operation of the BES, extending regulation in this way would have no
benefit for BES reliability. o “(e.g., a wind farm, or solar farm)” - Because the
SDT’s I4 text-box will be dropped from the final version, we believe this language
is necessary to clearly express the intent of the BES to cover utility-scale wind
farms, solar farms, and similar installations that consist of many relatively small
units that are aggregated for wholesale while excluding small, individually-owned
systems, such as rooftop solar PV arrays, that are not aggregated for the
Consideration of Comments: Project 2010-17 | September 2013
30
Organization
Yes or No
Question 1 Comment
wholesale market but are owned by and benefit individual retail customers o I4.a
- Imposing BES related Reliability Standards on individual small units is counterproductive and administratively burdensome. To the extent that applying
individual Reliability Standards to such small, non-aggregated units is
demonstrably necessary to protect BES reliability, application should be governed
by the language of individual Standards rather than by classifying such small
systems as BES. To that end, we are dedicated to drafting and vigorously
promoting a SAR to appropriately address the applicability of individual NERC
Standards to dispersed power-producing resources. o I4.b - We believe our
proposed wording: oAppropriately addresses impact to BES reliability. The
proposed language recognizes that reliability rests depends on TPs, BAs, RCs, and
TOPs responsibly addressing the single greatest contingency arising from, and the
behavior of, dispersed power producing resources in the aggregate. Enforcing
reliability standards on the owners of small, dispersed, and non-aggregated
resources is not productive and has no true value to BES reliability. Better aligns
with FERC’s Determination in Order 773 paragraph 114. , where FERC determined
that it will not direct NERC to include collector systems within wind farms and
similar generation systems in the BES through Inclusion I4. oAligns with FERC’s
Determination for I2 in Order 773 paragraph 91 and 92, that multiple step-up
transformers that connect generators to the BES at above 100-kV should be
included in the BES, while connections at lower voltages that operate as part of a
local distribution system should not be classified as part of the BES.
Tri-State Generation and
Transmission Association, Inc.
No
Consideration of Comments: Project 2010-17 | September 2013
The NERC draft shows a schematic for resources that aggregate at a single bus
location. Tri-State Generation and Transmission Association, Inc. (Tri-State) has
included a drawing (Sent via email to Wendy Muller (NERC Standards
Development Administrator-*see link at the end of the report)) that shows four
examples of distributed generation that could have been developed as phases of a
31
Organization
Yes or No
Question 1 Comment
single developer or as multiple developers. The drawings show Tri-State’s
interpretation of which elements (highlighted in yellow) would be included based
on the draft BES definition Inclusion I4. As written, it would include any line
element from the point where the aggregated generation exceeds 75 MVA
through the transformer that steps the voltage up to 100 kV or greater and
include every dispersed generator attached to the line, even if it is a solitary unit.
Please provide comments as to our interpretation. Inclusion I4a should be
deleted. It does not appear to follow the intent of the FERC Order 773. In Order
773, paragraph 106 “NERC states that the inclusion is meant to address the
dispersed power producing resources themselves, not the individual elements of
the collector systems operated below 100 kV.” Tri-State agrees with the EEI
comment within this paragraph, “that inclusion I4 applies to generating resources
meeting the threshold in the aggregate, not the individual generating units”.
There is no apparent requirement within the Commission Determination where
FERC is requiring this inclusion. Tri-State does not find the inclusion of individual
generating resources as low as 2MVA beneficial to the BES. A loss of a 2MVA
generating resource on low voltages does not pose the same risk as the loss of an
aggregated loss of 75MVA. If inclusion I4a is not deleted, a minimum MVA level
for the individual resource to be included in the BES should be added, just as I2
has. Tri-State recommends the Standard Drafting Team replace the current
ballot’s draft I4 language with:”The system designed primarily for delivering
capacity of dispersed power resources from the point where those resources
aggregate to greater than 75 MVA to a common point of connection at a voltage
of 100 kV or above.”
Consumers Energy Company
No
Consideration of Comments: Project 2010-17 | September 2013
The proposed wording of I4(b) is acceptable in that includes “...from the point
where resources aggregate to greater than 75 MVA...”. Consumers Energy objects
to I4 (a) which includes all “individual resources that aggregate to a total ampacity
32
Organization
Yes or No
Question 1 Comment
greater than 75 MVA”. This could be interpreted to include each of the small
generators, each 690V to 34.5kV transformer and the collector systems on a wind
farm. I4(a) should be removed from the BES definition leaving only I4(b) as an
inclusion. Consumers Energy recommends a negative ballot until the wind farm
generators, transformers and collector systems are excluded.
PacifiCorp
No
Consideration of Comments: Project 2010-17 | September 2013
The SDT has made significant progress by separating dispersed power producing
resources from traditional generating resources in Inclusion I2. By including I4
subpart (b), the SDT has identified the critical element(s) that impact reliability.
However, by failing to sufficiently address the real issue of the impact of the
mandatory reliability standards on individual dispersed power resources, the SDT
has perpetuated a gross error identified during phase one of the BES definition
project, by including each “individual” dispersed power producing resource as
potentially within the scope of the BES. During NERC’s August 21, 2013 webinar
on this project, the presenter emphasized the critical nature of the aggregate
generation of dispersed power producing resources for the reliability of the
interconnected transmission system. To that end, Inclusion I4 subpart (a) is
inconsistent with NERC’s express statements concerning the critical nature of the
generation in the aggregate. The presenter also indicated that those reliability
standards that apply to the GO/GOP functions should be addressed via a SAR in
order to modify those standards that impose an unreasonable burden on sectors
within the industry without providing a commensurate benefit to reliability.
PacifiCorp believes that the appropriate manner to address this discrepancy is in
fact not to submit a SAR to modify the standards, but rather to first eliminate
Inclusion I4 subpart (a) - and thus remove the collective set of individual resources
from within the BES - and then modify those standards in the future to address
any lingering reliability gaps that may apply to dispersed power producing
resources on an individual basis.PacifiCorp recommends the following language
33
Organization
Yes or No
Question 1 Comment
for I4:Dispersed Power Producing Resources: For dispersed power producing
resources that aggregate to a total capacity greater than 75 MVA, the system
designed primarily for delivering capacity from the point where such resources
aggregate to greater than 75 MVA to a common point of connection at a voltage
of 100 kV or above. Note: While individual dispersed power producing resources
are not considered part of the BES, that does not exempt registration as a GO or
GOP for those entities that solely own and/or operate such resources where the
aggregate is greater than 75 MVA. Dispersed power producing resources are
small-scale power generation technologies using a system designed primarily for
aggregating capacity providing an alternative to, or an enhancement of, the
traditional electric power system. Examples could include but are not limited to
solar, geothermal, energy storage, flywheels, wind, micro-turbines, and fuel cells.
PacifiCorp’s justification for this revised language is as follows: a dispersed power
producing resource necessarily consists of individual units of a limited size to take
advantage of the distributed nature of the resource (e.g., wind or solar) upon
which the facility relies for its fuel source. One benefit of such facilities’ unit size
and geographical distribution is that the facility is not as susceptible to a
substantial loss of generating capability as a single unit of 20 MVA or greater (the
registration threshold for a single generating unit). If the arrayed generators were
each 2 MVA then the probability of losing 20 MVA at the generator level would be
.00000001%. If the units were 5 MVA each the probability of losing all four units at
the generator level would be .01%. The probability of losing a single 20 MVA unit
would be 10%. These variations illustrate that there will be different values
depending upon the arrayed generator’s size. Given the reliability advantage this
diversity affords it does not seem reasonable to treat this type of facility in the
same way as a single unit facility of 20 MVA or greater. As recognized by the SDT,
a dispersed generating facility of 75 MVA or greater (NERC Registry Criterion
Section III.c.2) can have an impact on the BES. To recognize this impact and to also
account for the dispersed nature and reliability advantage as described above,
Consideration of Comments: Project 2010-17 | September 2013
34
Organization
Yes or No
Question 1 Comment
PacifiCorp requests that the SDT exclude individual dispersed power producing
resources from the BES through a revised Inclusion I4 substantially similar to the
proposal above.A technical example of the impact of the loss of an individual wind
turbine to the BES is available from PacifiCorp to the SDT upon request.
MidAmerican Energy Company
No
Consideration of Comments: Project 2010-17 | September 2013
The SDT has made significant progress by separating dispersed power producing
resources from traditional generating resources. By including I4 subpart (b) the
SDT has identified the critical element(s) that impact reliability. However, by
failing to address the issue of reliability standards as they apply to individual
dispersed power resources, the SDT has perpetuated a gross error implemented in
phase one of the BES, by including each individual dispersed resource as BES.
During the 8/21/2013 webinar the presenter emphasized the critical nature of the
aggregate generation of dispersed power producing resources to the reliability of
the interconnected transmission system. I4 subpart (a) is inconsistent with the
stated critical nature of the aggregate generation. The presenter also indicated
that standards that apply to GO/GOP associated standards should be addressed
via a SAR to correct reliability standards that impose a burden on the industry
without providing a significant benefit to reliability. The appropriate manner to
address this discrepancy is not to submit a SAR to modify the standards that
would inappropriately invoke requirements on individual generators due to their
inclusion in the BES definition, but to eliminate I4 subpart (a) and modify
standards in the future to address any reliability issues that may be required of
individual dispersed power producing resource.The following language is
recommended for I4:Dispersed Power Producing Resources: Where dispersed
power producing resources aggregate to greater than 75 MVA the to a common
point of connection at a voltage of 100 kV or above. Note: Individual dispersed
power producing resources are not BES, but does not exempt registration as a GO
or GOP. Dispersed power producing resources are small-scale power generation
35
Organization
Yes or No
Question 1 Comment
technologies using a system designed primarily for aggregating capacity providing
an alternative to, or an enhancement of, the traditional electric power system.
Examples could include but are not limited to solar, geothermal, energy storage,
flywheels, wind, micro-turbines, and fuel cells. Justification: A dispersed power
generating facility necessarily consists of individual units of a limited size to take
advantage of the distributed nature of the resource (e.g., wind or solar) upon
which the facility relies for its fuel source. One benefit of such facilities’ unit size
and geographical distribution is that they are not as susceptible to a substantial
loss of generating capability as a single unit of 20 MVA or greater (the registration
threshold for a single generating unit). If the arrayed generators were each 2 MVA
then the probability of losing 20 MVA at the generator level would be
.00000001%. If the units were 5 MVA each the probability of losing all four units at
the generator level would be .01%. The probability of losing a single 20 MVA unit
would be 10%. These variations illustrate that there will be different values
depending upon the arrayed generator’s size. Given the reliability advantage this
diversity affords it does not seem reasonable to treat this type of facility in the
same way as a single unit facility of 20 MVA or greater. As recognized by the SDT
and FERC in Order No. 773, a dispersed generating facility of 75 MVA or greater
(NERC Registry Criterion Section III.c.2) can have an impact on the BES. To
recognize this impact and to also account for the dispersed nature and reliability
advantage as described above, it is requested that the individual power producing
resources be excluded from the BES.A technical example of the impact of the loss
of an individual wind turbine to the BES is available to the SDT upon request.
Volkmann Consulting, Inc
No
Consideration of Comments: Project 2010-17 | September 2013
There is no technical justification to include disperse generation into the BES
definition. The impact of the aggregation is studied and addressed in the FAC-001
and FAC-002 processes. Once the effects of dispatchability and frequency /
voltage control in aggregation are addressed and mitigated in these processes, the
36
Organization
Yes or No
Question 1 Comment
inclusion of each individual generator into the BES definition provides no further
value to the industry and reliability.
Xcel Energy
No
Consideration of Comments: Project 2010-17 | September 2013
To be clear, Xcel Energy is strongly supportive of the change made to Exclusion E1,
to raise the exclusion threshold for radial and local networks from 30 kV to 50 kV.
However, we are voting negative due the unnecessary inclusion of dispersed
power individual resources in Inclusion I4(a). We understand that the individual
dispersed generators ended up being included in the Phase I BES definition, but
based on the development history, it is clear that the industry did not believe they
should be included and thought they WERE NOT included. It wasn’t until the
guidance document was finalized that it was apparent where the drafting team
landed on the subject. Phase II of this project provides the best opportunity to
refine and improve the BES definition such that industry compliance efforts are
focused on activities that will truly have an impact on reliability. Please see our
detail comments and justifications below: While we strongly support the
separation of I2 and I4 and the 75 MVA threshold for aggregating facilities in
Inclusion I4 (b), Xcel Energy continues to disagree with the inclusion of small
individual dispersed generators per Inclusion I4 (a). We provided alternative
language for I4 in the last comment period. That recommendation still stands.
Including individual dispersed generators in the BES definition will cause a huge
diversion in work activities as entities are forced to simultaneously seek relief via
the Exception Process to exclude reliability insignificant individual dispersed
generators from their programs while at the same time attempting to modify their
existing compliance programs to accommodate individual dispersed generators in
the event that the exception applications are not approved. NERC and the
Regions will be faced with a huge backlog of exception requests for small
distributed generators while Generator Owners with dispersed generating assets
will struggle to implement reliability standards that were never drafted with the
37
Organization
Yes or No
Question 1 Comment
intent of being applicable to anything but large scale generating stations.In the
August 21, 2013 webinar, the BES definition drafting team indicated that its
justification for the 75 MVA aggregating threshold in I4 (b) was that 75 MVA is the
level that the drafting team believes that single failures resulting in the loss of
generation could have an appreciable impact on the grid. It seems inconsistent
that a 2 MVA individual dispersed generator is deemed significant to reliability but
the equipment that is utilized to connect individual dispersed generators totaling
to <75 MVA is deemed not significant to reliability. Furthermore, with no
requirement that the BES be contiguous, how can individual 2 MVA wind turbine
generator at a >75 MVA wind farm have a greater effect on BES reliability than an
identical individual 2 MVA wind turbine at a <75 MVA wind farm? With no
technical rationale or difference in effects on BES reliability, how can identical 2
MVA units legally be treated so differently? In the Consideration of Comments
document for the first draft of Phase II BES definition, the Drafting Team
acknowledged that there are both existing and pending reliability standards which
likely will need to be reviewed and revised to clarify or correct the applicability of
the standard requirements to small scale generation and recommended that the
industry create a SAR to call for this action. Relative to the approval and
implementation time frames being discussed for the new BES definition, we do
not believe any such action could be taken in a timely enough fashion to resolve
industry uncertainty and avoid major regulatory burden with no commensurate
improvement in grid reliability. Examples: o PRC-005-2 Protection System
testing - the based relay test requirements were developed with large generators
in mind, and differ significantly from requirements in DOE Order 661A, of 2005
that requires wind plants to meet Low Voltage Ride-Through (LVRT) and Power
Factor Design Criteria. These standards significantly change the protection scheme
applied to individual turbines, and is not addressed here. Wind turbine protection
systems are often integral to the wind farm control system and the PRC-005-2
requirements were developed for protection equipment typically applied on large
Consideration of Comments: Project 2010-17 | September 2013
38
Organization
Yes or No
Question 1 Comment
scale generation not wind farm control systems. o TOP-002 Normal Operations
Planning - Under R14 of this standard, an unplanned outage for any individual
wind turbine would require a status notification report from the GO to the
TO/TOP. This level of reporting, at typically less than 3 MVA, is much less that any
practical reliability threshold, and would simply result in a documentation effort
with no value.Similar concerns exist for FAC-008-3, PRC-001-1, PRC-004-2a, PRC019-1, PRC-024-1, and PRC-025-1, and other standards where it is quite evident
that small scale dispersed generators were not considered during the standard's
development. Unless Inclusion I4 (a) is eliminated, we do not believe
implementation of the new BES definition should go forward until all reliability
standards have been reviewed and revised as necessary to clarify the applicability
to individual dispersed generating assets. What reliability benefit is there to a
"bright line" BES definition if there is not a corresponding clarity in the
applicability of reliability standards to the elements deemed to be included in the
BES?
Wisconsin Public Service
Corporation
No
Consideration of Comments: Project 2010-17 | September 2013
We agree with including the Generating stations with dispersed generation from
the point of aggregation to 75 MVA as I4-b does. We agree with the statement
made on the BES Phase II webinar of August 21 that this is the point where the
dispersed power plant is significant to the reliability of the BES. We disagree with
including the individual resources themselves since, as indicated on the webinar,
they are not significant to the reliability of the BES . Including dispersed power
producing resources less than 25MVA ignores differences in engineering design
and operating philosophies. For our company each 2MVA wind turbine is designed
to sync on and off the grid several times a day. For this reason, the engineering
design incorporates a large contactor to handle these operations. This contactor is
controlled by the turbine PLC which contains the main protective relay functions
(i.e. frequency, over/under voltage, imbalance...etc) traditionally contained in
39
Organization
Yes or No
Question 1 Comment
discrete protective relays. A generator breaker is designed in series with the
contactor, which includes a self contained overcurrent element that serves as a
backup function, but is different in traditional design in that each Protection
Component is contained in the breaker device. Due to the PLC control/protection
integration, equipment differences, and operating philosophies implementation of
NERC Reliability Standards such as PRC-004, PRC-005 and FAC-008 would be
impractical and onerous lending little to no reliability improvement.We suggest
eliminating I4a completely since, as indicated on the webinar I4b encompasses
the portion of the dispersed power generating plant that is significant to the
reliability of the BES
American Wind Energy Association
No
Consideration of Comments: Project 2010-17 | September 2013
While we strongly support the separation of I2 and I4 and the 75 MVA threshold
for aggregating facilities in Inclusion I4 (b), and the exclusion of collector system
components that aggregate less than 75 MVA of generation, we still strongly
disagree with the inclusion of small individual dispersed generators per Inclusion
I4 (a). This problem can be resolved by either removing I4 (a) in its entirety or
revising it to clarify that the only BES-relevant standards that apply to individual
dispersed generators are those that affirmatively state that they apply to
dispersed generators. While individual generators were included in the Phase I
BES definition, that is not a compelling reason why they should also be included in
Phase II. Phase II of this project provides an opportunity to refine and improve the
BES definition such that industry compliance efforts are focused on activities that
will truly have a beneficial impact on reliability. Including individual dispersed
generators in the BES definition will cause a major diversion away from efforts
that improve BES reliability, as entities are forced to simultaneously seek relief via
the Exception Process to exclude individual dispersed generators that are
insignificant from a reliability standpoint from their programs while at the same
time attempting to modify their existing compliance programs to accommodate
40
Organization
Yes or No
Question 1 Comment
individual dispersed generators in the event that the exception applications are
not approved. With more than 45,000 wind turbines installed in the U.S. and the
vast majority of them in wind plants larger than 75 MVA, NERC will be faced with
a huge backlog of exception requests for small distributed generators while
Generator Owners with dispersed generating assets struggle to implement
reliability standards that were never drafted with the intent of being applicable to
anything but large scale generating stations. As a result, proceeding with the BES
definition as currently drafted would actually impair, rather than improve, bulk
electric system reliability.In the Consideration of Comments document for the first
draft of Phase II BES definition, the Drafting Team acknowledged that there are
both existing and pending reliability standards which likely will need to be
reviewed and revised to clarify or correct the applicability of the standard
requirements to small-scale generation and recommended that the industry
create a SAR to call for this action. Relative to the approval and implementation
time frames being discussed for the new BES definition, we do not believe any
such action could be taken in a timely enough fashion to resolve industry
uncertainty and avoid a major regulatory burden that would distract from efforts
that actually improve grid reliability. Examples of standards that were not drafted
with small dispersed generators in mind include: o PRC-005-2 Protection System
testing - the relay test requirements were developed with large generators in
mind, and differ significantly from requirements in FERC Order 661A, of 2005 that
require wind plants to meet Low Voltage Ride-Through (LVRT) and Power Factor
Design Criteria. These standards significantly change the protection scheme
applied to individual turbines, and there is no clarity about how they should be
applied. Wind turbine protection systems are often integral to the wind farm
control system and the PRC-005-2 requirements were developed for protection
equipment typically applied to large-scale generation, not wind farm control
systems. o TOP-002 Normal Operations Planning - Under R14 of this standard, an
unplanned outage for any individual wind turbine would require a status
Consideration of Comments: Project 2010-17 | September 2013
41
Organization
Yes or No
Question 1 Comment
notification report from the GO to the TO/TOP. While such a report can be
important for large central station generation, it would provide no value for a
small individual wind turbine generator. This level of reporting, at typically less
than 3 MVA, is much lower that any practical reliability threshold, and would
simply result in a documentation effort with no value.Similar concerns exist for
FAC-008-3, PRC-001-1, PRC-004-2a, PRC-019-1, PRC-024-1, and PRC-025-1, and
other standards in which small-scale dispersed generators were not considered
during the standards’ development. Unless Inclusion I4 (a) is eliminated, or
significantly revised to clarify that the only BES-relevant standards that apply to
dispersed generators are those that affirmatively state that they apply to
dispersed generators, we do not believe implementation of the new BES definition
should go forward until all reliability standards have been reviewed and revised as
necessary to clarify the applicability to individual dispersed generating assets.
What reliability benefit is there to a "bright line" BES definition if there is not a
corresponding clarity in the applicability of reliability standards to the elements
deemed to be included in the BES? On the August 21, 2013 webinar, the BES
definition drafting team indicated that its justification for the 75 MVA aggregating
threshold in I4 (b) was that 75 MVA is the level that the drafting team believes
that single failures resulting in the loss of generation could have an appreciable
impact on the grid. While we support the exclusion of collector system
components that aggregate less than 75 MVA, it seems inconsistent that a 2 MVA
individual dispersed generator is deemed significant to reliability but the
equipment that is utilized to connect multiple dispersed generators totaling up to
75 MVA is deemed not significant to reliability. The logic that led to the exclusion
of collector system equipment that aggregates less than 75 MVA, as well as the
logic expressed on the webinar that 75 MVA is the threshold at which the loss of
generation could have an impact on BES reliability, argues for also excluding
individual dispersed generators. Furthermore, what is the logic of including
individual 2 MVA wind turbine generator at a >75 MVA wind farm while excluding
Consideration of Comments: Project 2010-17 | September 2013
42
Organization
Yes or No
Question 1 Comment
individual 2 MVA wind turbine at a <75 MVA wind farm? With no technical
rationale or difference in effects on BES reliability, how can identical 2 MVA units
be treated so differently? The only compelling reason for applying BES standards
to individual dispersed generators would be if there were a real risk of an abrupt
common mode failure affecting a large share of the dispersed generators in a >75
MVA wind plant. However, per FERC Order 661A, wind turbine generators already
comply with voltage and frequency ride-through standards that are far more
stringent than those that apply to other types of generators. As a result, if a
common mode failure caused by a grid disturbance were to affect the wind
turbines in a >75 MVA wind plant, the impact on the wind plant would be
irrelevant for grid reliability because the voltage and/or frequency deviation
would have already caused most if not all of the conventional generators in the
grid operating area to trip offline. While weather-driven changes in wind speed
can significantly change the aggregate output of a wind plant, those changes in
output occur too gradually to pose a risk to bulk power system reliability, and
regardless such changes in output would not be regulated or mitigated by BESrelevant standards. No compelling rationale has been offered for why including
individual dispersed wind turbine generators in the BES definition will improve
grid reliability.
Wisconsin Electric Power Company
No
Consideration of Comments: Project 2010-17 | September 2013
Wisconsin Electric appreciates the work the Standard Drafting Team (SDT) has
accomplished, but is concerned that the team has not corrected a fatal flaw in the
definition of the Bulk Electric System. During the 8/21 webinar, the SDT said that
they don’t have the power to change an existing approved definition with regard
to the inclusion of individual distributed generation resources, yet that’s what
they in fact do every time they draft a standard revision. FERC accepted the Phase
1 definition, but we believe the SDT had the opportunity to correct the flawed
definition. The SDT team did not address industry’s comments that individual
43
Organization
Yes or No
Question 1 Comment
wind turbines (and other dispersed generating units) should not be included in the
definition. The SDT stated that industry has the option to address whether
dispersed generation should be applicable to a standard by revising the
applicability of those standards. This method of correcting for the wrong
elements’ inclusion in the definition will take time and resources from the
industry. During this time period, the industry would still need to assume
responsibility for compliance to each affected standard because it would be
unknown when/if the revisions would be accepted and approved. For instance,
compliance to Reliability Standard PRC-005 requires the industry to include
thousands of individual wind turbines (and small solar panels) in the maintenance
and testing of relays and associated equipment. Resources required to complete
this testing are specialized and significant, with little to no measureable benefit to
the BES (and an indirect detriment by taking those resources away from other
tasks that are beneficial). In regards to CIP Version 5 requirements, if each wind
turbine is part of the BES, then each wind turbine’s monitoring and control
systems will be “BES Cyber Systems”. Again, resources will be required for
compliance with no benefit to reliability.Individual dispersed generation units
(generally less than 2 MW) do not impact the reliability of the Bulk Electric
System. The SDT points out that it is not including collector circuits of dispersed
generators because collector circuits do not have a true reliability impact, but the
SDT fails to recognize that the individual dispersed generators have even less of an
impact. The issue of concern is a single point of failure affecting 75 MWs of
generation, not the failure of an individual wind turbine. By excluding the
collector systems, but including the individual generators, the SDT team is not
following FERC’s Order 773 (issued 12/20/2012) Paragraph 165, in which the
Commission stated that it is appropriate to have the bulk electric system
contiguous, without facilities or elements “stranded” or “cut-off” from the
remainder of the bulk electric system. The individual dispersed generating units
are stranded from the remainder of the bulk electric system in the current draft of
Consideration of Comments: Project 2010-17 | September 2013
44
Organization
Yes or No
Question 1 Comment
the definition.The SDT stated during the 8/21 webinar, that industry can use the
exception process to exclude wind turbines, or other dispersed generators. This
viewpoint has a fundamental problem. It mandates that individual generators be
included in a faulty definition that pulls in insignificant elements into the BES and
then requires industry to exclude them (essentially an entire asset type). That
requires hundreds of dispersed generator owners to rely on the regulator to be
reasonable and allow us to exclude all of our individual dispersed generators. The
proposed Phase 2 definition poses a huge compliance and regulatory burden that
doesn’t add to the reliability of the BES.
BANC & SMUD
No
Although we believe the Drafting Team has provided vast improvement to the
Draft #2 of the Phase 2-I4 BES Definition SMUD is posting a Negative position for
Draft #2 for the following reasons. Salient Issues: o In accordance with
Paragraph 115 of the Commission’s Order 773, exclude the collector system from
the BES definition.
o Wind/Solar BES delineation should be limited the GSU where the total plant
capacity is connected at a common point to 100kV or greater.
o During Phase-1, it was suggested that a 75 MVA threshold be established where
the loss of a single element would render the entire 75 MVA of resources
unavailable. This was in lieu of including the individual small-scaled machines as
BES to avoid subjecting those machines to administrative burden for little or no
impact on the BES as compared to the compliance obligation.
o Redundant to TPL & TOP standards where loss of the resource(s) for a single
element is addressed in system studies that include evaluation for adequate level
Consideration of Comments: Project 2010-17 | September 2013
45
Organization
Yes or No
Question 1 Comment
of resources, system impacts and Single Largest Contingencies.
o Must include the phrase “(e.g., wind or solar)” after “Dispersed power
producing resource projects” to fully clarify the applicability of Inclusion I4.
o Support a Standard Authorization Request or other mechanism to reduce
administrative burden for compliance to specific standards (e.g., PRC-004
(Misoperations) & PRC-005 (Maintenance & Testing).
The following is suggested wording for I4 that are associated with the points
above: “I4 - Dispersed power producing resource projects, or portion(s) thereof,
designed primarily for supplying wholesale power (e.g., a wind farm, or solar farm)
that aggregate to a total capacity greater than 75 MVA (gross nameplate rating) at
a common point of connection to a voltage of 100 kV or above consisting of: a)
The individual resources, and b) The delivery system designed primarily for
delivering capacity from i) the point where those resources aggregate to the total
connected capacity; to ii) a common point of connection at a voltage of 100 kV or
above.”
Rationale:1. “projects ... designed primarily for wholesale...”: Nothing in this
posted version distinguishes between generation for retail (behind the meter) and
generation for wholesale. As such, rooftop PVs, generator assistance programs, or
other similar small power-producing incentives, might be otherwise interpreted as
included under I4.2. “(e.g., a wind farm, or solar farm)”: Because the SDT’s I4 textbox will be dropped from the final version, we believe this inclusion is necessary
to retain an illustration of the intent.
3. I4.a:While applying BES NERC Reliability Standards to the management of
individual small units is counter-productive and administratively burdensome, we
Consideration of Comments: Project 2010-17 | September 2013
46
Organization
Yes or No
Question 1 Comment
do agree that differentiating applicability of various Standards should be specified
within those Standards.
4. I4.b: We believe the proposed wording: a. Appropriately addresses impact to
BES reliability. Rather than offering some illusion for reliability at a lesser impact
level, this proposal recognizes that reliability rests in TPs, BAs, RCs, and TOPs
responsibly addressing the single greatest contingency arising from, and the
behavior of, dispersed power producing resources in the aggregate. Enforcing
governance for management to any lesser level is not productive and has no true
value to BES reliability. b. Better aligns with FERC’s Determination within Order
770 paragraph 114.c. Aligns with FERC’s Determination for I2 within Order 773
paragraph 91.d. Aligns with FERC’s Determination for I2 within Order 773
paragraph 92.
New York Power Authority
No
Inclusion 4b does not support a contiguous BES due to the exclusion of a portion
of the path from the generator terminals to the resource aggregation point.
Inclusion 4b is not consistent with the elements included under Inclusion I2 which
applies to all generating resources.
Response: The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
Consideration of Comments: Project 2010-17 | September 2013
47
Organization
Yes or No
Question 1 Comment
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
East Kentucky Power Cooperative
No
In the consideration of comments, the drafting team indicated that a SAR might
be submitted to appropriately adjust GO and GOP standards requirements for
dispersed generating facilities. We agree that is the approach to undertake. In
order to support this approach, I4 should be deleted to avoid the situation where
inappropriate provisions could become effective and compliance become difficult
or impossible for entities until work is completed through the SAR to adjust those
requirements. In the filing with FERC this procedure could be explained so that
FERC can be assured that their approval of inclusion of dispersed generating
facilities in the Phase I order will be appropriately implemented.
Response: The SDT is charged with resolving the definition in total at this time and can’t point to future possible outcomes for
resolution. The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options equated to an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
Consideration of Comments: Project 2010-17 | September 2013
48
Organization
Yes or No
Question 1 Comment
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
Southwest Power Pool Regional
Entity
No
Separation of I2, no issue
No: 75MVA threshold may be higher than what FERC will support. Comments:
Paragraph 167 of Order 773 implies that FERC sees the aggregation point for tie
lines at 20MVA. However, there was some flexibility provided in the rehearing
comments on this point.
Paragraph 113 of Order 773 states that multiple step-up transformers (in
particular 34.5/115kV) are expected to be included by FERC.
Response: Paragraph 167 speaks to embedded generation in a radial system and is not pertinent to Inclusions I2 or I4. The SDT
believes that there is support for the 75 MVA threshold for aggregation. No change made.
The Reference Document shows examples of where and when multiple step-up transformers are to be included in the BES. No
change made.
Public Service Enterprise Group
No
Consideration of Comments: Project 2010-17 | September 2013
The proposed elimination of the “collector system” as part of the BES makes the
BES non-contiguous. In Order 773, the Commission (P 113 and P 114) stated that
radial collector systems used solely to aggregate generation SHOULD be part of
the BES since multiple transformers connections did not exempt I2 generators.
49
Organization
Yes or No
Question 1 Comment
However, FERC did not direct NERC to include the collector system in the BES.
However, it did require that radial lines that connect I2 generators (call “tie lines”
in Order 773) should be part of the BES (P 164-P 167) for reasons of contiguity.
This BES definition proposed in Phase 2 creates an unlevel competitive
environment between I4 generators and I2 generators. Moreover, in its SAR for
Phase 2, the question of BES contiguity was supposed to be addressed. The
team’s response on this issue allows dispersed power generators to be noncontiguous from the point where ac power is produced to where it is injected into
the grid. The connections of I2 BES generators are, however, ARE included in the
BES. In the diagram shown in the comment form, if the dispersed generators
were forty 2 MVA diesel generators connected as shown, would their collector
system be excluded from the BES also? What is there were eight 10 MVA gas
turbines connected via a collector system? How about six 16 MVA gas turbines?
As a member of the RBB, we direct that the team include collector systems that
are solely used to aggregate generation in the BES definition.
Response: The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
Consideration of Comments: Project 2010-17 | September 2013
50
Organization
Yes or No
Question 1 Comment
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
Gas turbine and diesel generators are handled through Inclusion I2. In the examples shown in the comment, generation aggregates
to greater than 75 MVA so the generation and equipment connecting that generation to a common point operated at 100 kV or
above is included.
NIPSCO
No
We requested some clarification regarding a wind farm within NIPSCO from
members of the SDT, and promptly received feedback. The main concern is that
we are not sure of the intent of inclusion I4 because it is attempting to include a
bus within an intermediate voltage. In our case it is 69 kV that may or may not be
included since there are 2 transformations within the path to the 138KV; 1 up to
69 kV and 2 parallel transformers up to the 138 kV. In addition the entire 69 kV
path is not “designed primarily for delivering” this wind power to the 138 kV
system; the 69 kV system includes many lines serving various demand. Some on
the SDT felt that the single step-up transformer is the same as 2 transformers in
parallel, while others did not. Following this discussion we failed to receive a
uniform clarification. Some opinions were that the 69 kV system would be
included in the BES while others believed it would not; we have similar differing
interpretations within NIPSCO. Further clarification needs to be made on whether
or not multiple transformations are or are not included.
Response: The SDT is not allowed to offer opinions on compliance issues. All that the SDT can do is to show its intent when it
crafted the definition. This intent is shown in the Reference Document which shows several examples of multiple transformation
configurations for consideration.
Consideration of Comments: Project 2010-17 | September 2013
51
Organization
Yes or No
Question 1 Comment
Nebraska Public Power District
Yes
Still have concern with including individual wind turbines as it relates to total
generation.
ACES Standards Collaborators
Yes
(1) We thank the drafting team for separating dispersed power producing
resources to a separate inclusion category. This avoids some of the confusion in
the prior posting.
(2) We have a question regarding the diagram provided in the comment form.
Why is each generating unit considered a part of the BES? Wouldn’t the point of
aggregation be the first BES element? If a single dispersed power producing
resource fails, there is no impact on the BES. We request the drafting team
consider this aspect.
Transmission Access Policy Study
Group
Yes
Consideration of Comments: Project 2010-17 | September 2013
Although we support the SDT’s willingness to address the lack of clarity caused by
the previous posting’s merging of I4 with I2, we are concerned that the wording of
the new version of I4 does not capture the SDT’s intent, and could lead to absurd
results if read literally. As we understand it, the SDT’s intent is to include only
dispersed power producing resources that both (a) aggregate to more than 75
MVA, and (b) are connected through a system designed primarily for delivering
capacity at a common point of connection of 100 kV or above. We believe that
the SDT also intends that only the individual resources and the point from which
they aggregate to 75 MVA should be included in the BES; in other words, the
portion of the collector system that carries <75 MVA is not BES by virtue of I4. In
order to express that intent clearly, we suggest the following revised text: I4 Dispersed power producing resources that aggregate to a total capacity greater
than 75 MVA (gross nameplate rating), and that are connected through a system
52
Organization
Yes or No
Question 1 Comment
designed primarily for delivering such capacity from the point at which those
resources aggregate to greater than 75 MVA to a common point of connection at
a voltage of 100 kV or above. The BES portion of such resources includes: a) The
individual resources, and b) The system designed primarily for delivering capacity
from the point where those resources aggregate to greater than 75 MVA to a
common point of connection at a voltage of 100 kV or above. We believe that this
text is consistent with the intent reflected in the diagram provided by the SDT in
the comment form, and is more clear and accurate than the text of I4 as posted.
ReliabilityFirst
Yes
Even though ReliabilityFirst votes in the Affirmative, ReliabilityFirst is aware of
some concerns among Registered Entities for the potential issue of individual
wind units (i.e. single generators) being required to register based on the language
of the revised definitions (specifically I4). Though ReliabilityFirst staff agrees with
I4 and does not believe this is an issue, ReliabilityFirst recommends NERC and the
Regional Entities come up with a common understanding on how Entities are
registered based on their ownership of wind units which are designated as BES
through the new definition.
Hydro One
Yes
We reluctantly support the separation of I2 and I4 because we believe that their
wordings in the BES definition as approved by the industry, NERC BOT, FERC and
applicable governmental authorities in Canada should have been retained. In our
opinion, I4 is meant for renewable energy resources (in particular Wind). These
resources are inherently different when considered for planning and for real time
operations. This change will essentially designate every element of a wind farm
above 75MVA to its interconnection at 100kV as a BES element including the
medium voltage collector systems (less than 50kV) adding burden which may not
be necessary. Further, it is not clear what and how standards will apply to
Consideration of Comments: Project 2010-17 | September 2013
53
Organization
Yes or No
Question 1 Comment
collector systems designated as BES.
Response: The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
Duke Energy
Yes
Duke Energy agrees with the changes made by the SDT.
Arizona Public Service Company
Yes
This change returns it to the original language in Phase I. Either way it still has the
same intent.
Southern California Edison
Yes
SCE believes that the revision to I4, the inclusion for dispersed power producing
resources, is a move in the right direction, but we think that additional clarity
Consideration of Comments: Project 2010-17 | September 2013
54
Organization
Yes or No
Company
Question 1 Comment
could be provided by changing "common point of connection" to "common point
of interconnection".
Response: The SDT does not see where the suggested change adds any clarity to the text. No change made.
SPP Standards Review Group
Yes
While we don’t have an issue with separating I4 from I2 as in the previous draft,
we do have concern with the wording of the inclusion, especially the phrase
‘primarily designed’. While the diagram provided in the comment form clearly
shows the distinction, it is difficult to pull it from the wording of I4. Additionally,
we are confused by what was explained during the NERC industry webinar and
what is shown in the above figure. The figure and the words in I4 indicate the
point of aggregation is included in the BES. The discussion during the webinar did
not include it in the BES.
Response: The SDT points the commenter to the Reference Document where it shows the aggregation point and how it is handled
within the definition.
Southern Company
Yes
Northeast Power Coordinating
Council
Yes
Dominion
Yes
Consideration of Comments: Project 2010-17 | September 2013
The separation of dispersed generation where a collector system aggregates the
total generation prior to connecting to the BES is clear in I4.
55
Organization
Yes or No
SERC Planning Standards
Subcommittee
Yes
Bonneville Power Administration
Yes
Salt River Project
Yes
Pepco Holdings Inc
Yes
Exelon and its' affiliates
Yes
Independent Electricity System
Operator
Yes
Ameren
Yes
Manitoba Hydro
Yes
Hydro-Quebec TransEnergie
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 1 Comment
56
Organization
Yes or No
Idaho Power Company
Yes
City of Tallahassee
Yes
Question 1 Comment
Response: Thank you for your support. The SDT is retaining Inclusion I4a but has changed the language of this inclusion to provide
greater clarity of the SDT’s intent based on industry comments.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
Consideration of Comments: Project 2010-17 | September 2013
57
2. The SDT has proposed an equally effective and efficient alternative to the Commission’s sub-100 kV loop concerns for radial
systems by the addition of Note 2 in Exclusion E1 with a threshold value of 50 kV, and posted a technical rationale to support this
threshold. Do you agree with this threshold? If you do not support this threshold, please provide specific suggestions and
technical rationale in your comments.
Summary Consideration: Some commenters suggested raising the threshold value above 50 kV. However, no technical rationale for
doing so was presented in the comments. Without such rationale, the SDT is unable to entertain such suggestions.
The SDT believes that the 50 kV threshold is an appropriate continent-wide, bright-line value for reliability of the BES. The selection of
this value is not due to a FERC directive but is based on physical principles. Therefore, the SDT sees no reason for a reference to non-US
Registered Entities.
No changes were made to the proposed definition due to comments raised in this question.
Organization
Yes or No
Ameren
No
Question 2 Comment
In our opinion, the SDT has improved the E1 exclusion criteria by increasing the 30
kV threshold to 50 kV. However, we still believe that the threshold is too low and
request that it be raised to at least 70 kV. As the definition now stands, we will
have to perform what we feel is unnecessary analysis to prove that most of our
local subtransmission networks should also be excluded.
Response: The commenter has presented no technical rationale for increasing the threshold value above 50 kV. The studies
performed by the SDT indicate that 50 kV is the highest supportable threshold value, i.e., where the loop configuration starts to flow
back to the BES and may be considered necessary for the reliable operation of the interconnected transmission system. No change
made.
Organization
Yes or No
Arizona Public Service Company
No
Question 2 Comment
Note two was added in draft 1 to Phase II. This change to Note 2 changes it from
30KV to 50KV, due to analysis they performed. 50KV threshold is less restrictive
than 30KV. FERC forced Note 2 - this note requires determining loops between
radial lines, and including radials with >50 KV loops
Response: The SDT fails to see a question or suggestion here and is thus unable to provide a response.
American Electric Power
No
The thought process of the note #2 is confusing the process. One could take this
to mean that a 69 kV system would be included by exclusion. AEP does not
believe this to be the case, but the wording of this note does not lead to an
obvious conclusion. We suggest that the SDT make another attempt to provide a
simpler and clearer approach.
AEP also suggests that E1 have transmission removed from between the words
contiguous and Elements. We recommend that it instead say “Radial systems: A
group of contiguous Elements that emanates from a single point of connection of
100 kV or higher and:”
Response: The SDT reviewed the contents of the note and believes that the wording is clear. No change made.
The SDT has previously explained the rationale for inclusion of the word ‘transmission’ and believes that the rationale is still
appropriate. The word transmission is not capitalized and is used as a qualifier to the word Element and is meant to differentiate
between the types of Elements that are identified in the NERC Glossary of Terms Used in NERC Reliability Standards definition of
Element.
Element (NERC Glossary of Terms):
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components.”
Consideration of Comments: Project 2010-17 | September 2013
59
Organization
Yes or No
Question 2 Comment
The use of the words: “a group of contiguous transmission Elements,” means Elements originating at a voltage of 100 kV or higher
that are connected in a contiguous manner. No change made.
Nebraska Public Power District
No
Consideration of Comments: Project 2010-17 | September 2013
The white paper for the low voltage loop threshold is a logical review of the issues.
We would like to see some clarification for certain configurations. For example,
two 115kV/69kV parallel transformers at the same substation serving only load at
69kV and no looped 69kV lines: 1) with 115kV and 69kV bus tie breakers, 2) with
no 115kV bus tie breaker but does have a 69kV tie breaker, 3) with no 115kV bus
tie breaker and no 69kV tie breaker, and 4) with 115kV bus tie breaker and no
69kV tie breaker. All breakers are normally closed but if no breakers exist then
transformers are connected directly by bus operating in parallel for all cases. Does
this make the interrupting device on the high side of each transformer BES
elements? Does this make the transformer a BES element or suggest an analysis
for an exception must be made to remove them from the BES? Our concern is how
a PRC-005 audit/enforcement group will interpret these configurations if it is not
clearly stated in an example or considered in the white paper. How would the SDT
interpret a configuration where a 115kV “radial” line feeds a substation with a
56MVA 115/69kV transformer. The 69kV side of the transformer is connected to a
networked 69kV system owned by another entity. The 69kV system does connect
back to the transmission system in multiple points in the other entities system.
There is some 69kV generation greater than 20MVA or 75MVA aggregate but the
substation and line in question is not used for black start. Note the 115kV/69kV
transformer would never allow greater than 75MVA to pass through it back to the
115kV line since the transformer is too small. Is the substation with the 115/69kV
transformer a BES substation? Is the 115kV line to the 115kV/69kV substation
BES? Please clarify. It seems transformer size should have some impact but the
reference document does not reference this.
60
Organization
Yes or No
Question 2 Comment
Response: The SDT is not allowed to provide advice on adherence/compliance to entities. The best that it can do is to provide
examples as to the intent of the SDT when it was writing the definition. Such examples have been provided in the Reference
Document and this document will be updated to show the Phase 2 changes as quickly as possible.
Hydro One
Yes
We agree that 50kV is more reasonable and are voting positively to the change
made by SDT. This change was essentially initiated to address a FERC directive in
its Order 773. However it should be noted that the demarcation point between
transmission and distribution may be different in non FERC jurisdictions, such as
Canadian provinces. In establishing voltage thresholds, NERC needs to consider
non-US legislated demarcation points, and the standard development process
must make allowances for such regulatory and/or jurisdictional differences and
frameworks consistent with NUC 001 and TPL footnote b. We suggest that NERC
and the SDT consider revising Note 2 to read as follows: Note 2 - The presence of
a contiguous loop, operated at a voltage level of 50 kV or less, between
configurations being considered as radial systems, does not affect this exclusion.
Non-US Registered Entities can adopt the same voltage level or should
implemented in a manner that is consistent with, or under the direction of, the
applicable governmental authority or its agency.
Independent Electricity System
Operator
Yes
We suggest that NERC and the SDT consider revising Note 2 to read as follows:
Note 2 - The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect
this exclusion. Non-US Registered Entities can adopt the same voltage level or
should be implemented in a manner that is consistent with, or under the direction
of, the applicable governmental authority or its agency.
Response: The SDT believes that the 50 kV threshold is an appropriate continent-wide, bright-line value for reliability of the BES.
Consideration of Comments: Project 2010-17 | September 2013
61
Organization
Yes or No
Question 2 Comment
The selection of this value is not due to a FERC directive but is based on physical principles. Therefore, the SDT sees no reason for a
reference to non-US Registered Entities. No change made.
SERC Planning Standards
Subcommittee
Yes
In our opinion, the SDT has improved the E1 exclusion criteria by increasing the 30
kV threshold to 50 kV. We wish to thank the SDT for its diligence in justifying an
increase to 50 kV. However, we still believe that the threshold is too low and
would like to see it raised to at least to 70 kV.
Response: The commenter has presented no technical rationale for increasing the threshold value above 50 kV. The studies
performed by the SDT indicate that 50 kV is the highest supportable threshold value, i.e., where the loop configuration starts to flow
back to the BES and may be considered necessary for the reliable operation of the interconnected transmission system. No change
made.
Associated Electric Cooperative,
Inc. - JRO00088
Yes
AECI appreciates the SDT's willingness to tackle this issue and provide a higher kV
level than 0, as well as its technical justification.
Duke Energy
Yes
Duke Energy agrees with the modifications made by the SDT.
Indiana Municipal Power Agency
Yes
IMPA appreciates the work that the SDT has done to come up with an alternative
to the Commission’s sub-100kV loop concerns for radial systems. IMPA supports
the SDT’s white paper and the proposed 50kV threshold value.
Southern Company
Yes
It is clear that looping facilities operating at voltages < 100 kV are NOT included in
the BES and that contiguous loops operated at voltage < 50 kV in configurations
Consideration of Comments: Project 2010-17 | September 2013
62
Organization
Yes or No
Question 2 Comment
being considered as radial systems does not affect this exclusion (i.e., they are also
NOT included in the BES).
Transmission Access Policy Study
Group
Yes
TAPS appreciates the SDT’s work on the sub-100 kV loop issue. For the reasons set
out in the SDT’s white paper, and in TAPS’ comments on the 30 kV threshold that
was proposed in the first posting of Phase 2 of the BES definition project, TAPS
strongly supports the proposed 50 kV threshold.
Southwest Power Pool Regional
Entity
Yes
The technical justification document supports this conclusion.
Wisconsin Public Service
Corporation
Yes
We agree with the 50kv limit since the SDT has posted a reasonable technical
rationale.
ACES Standards Collaborators
Yes
We thank the drafting team for increasing the minimum threshold to 50 kV for
sub-100 kV looped radial systems.
NIPSCO
Yes
We'd rather see it at 70 kV, however we appreciate the analysis that was
performed justifying the 50 kV.
Xcel Energy
Yes
Xcel Energy strongly supports this modification.
Consideration of Comments: Project 2010-17 | September 2013
63
Organization
Yes or No
Northeast Power Coordinating
Council
Yes
Dominion
Yes
SPP Standards Review Group
Yes
Florida Municipal Power Agency
Yes
BANC & SMUD
Yes
Bonneville Power Administration
Yes
Salt River Project
Yes
PacifiCorp
Yes
Madison Gas and Electric Company
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 2 Comment
64
Organization
Yes or No
Pepco Holdings Inc
Yes
Muscatine Power and Water
Yes
Public Service Enterprise Group
Yes
Exelon and its' affiliates
Yes
MidAmerican Energy Company
Yes
BrightSource Energy, Inc.
Yes
Consumers Energy Company
Yes
Alliant Energy
Yes
Manitoba Hydro
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 2 Comment
65
Organization
Yes or No
Hydro-Quebec TransEnergie
Yes
New York Power Authority
Yes
Omaha Public Power District
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
Volkmann Consulting, Inc
Yes
Tri-State Generation and
Transmission Association, Inc.
Yes
MRO
Yes
American Transmission Company,
LLC
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 2 Comment
66
Organization
Yes or No
First WInd
Yes
Minnkota Power Cooperative
Yes
Public Utility District No.1 of
Snohomish County
Yes
Question 2 Comment
Response: Thank you for your support.
Consideration of Comments: Project 2010-17 | September 2013
67
3. The SDT has added the term ‘Real’ to Exclusion E3b to clarify its intent. Do you agree with this change? If you do not support this
change, please provide specific suggestions and technical rationale in your comments.
Summary Consideration: There were no negative comments regarding this change.
No changes were made to the proposed definition due to comments raised in this question.
Organization
Yes or No
SPP Standards Review Group
Yes
Question 3 Comment
This change has been made to clarify the drafting team’s intent. We would be
interested in knowing what that intent is.
Response: The intent of the SDT was to clarify that Real Power is the issue with regard to local networks. Reactive Power is a local
issue and not easily or customarily transferred outside of the local network.
Ameren
Yes
We agree with the addition of the word “Real”, but we have other concerns with
E3b and we have identified in the comments to question 4 below.
Response: Please see the response to Q4.
Southern California Edison
Company
Yes
Clearly identifying "Real" Power makes sense and helps clarify the intent.
NIPSCO
Yes
good
Consideration of Comments: Project 2010-17 | September 2013
68
Organization
Yes or No
Arizona Public Service Company
Yes
Northeast Power Coordinating
Council
Yes
Dominion
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power Agency
Yes
BANC & SMUD
Yes
Bonneville Power Administration
Yes
Duke Energy
Yes
Associated Electric Cooperative,
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 3 Comment
This is in regard to local networks and this change is less restrictive.
69
Organization
Yes or No
Question 3 Comment
Inc. - JRO00088
ACES Standards Collaborators
Yes
Southwest Power Pool Regional
Entity
Yes
Salt River Project
Yes
Southern Company
Yes
PacifiCorp
Yes
Wisconsin Public Service
Corporation
Yes
Madison Gas and Electric
Company
Yes
Pepco Holdings Inc
Yes
Consideration of Comments: Project 2010-17 | September 2013
70
Organization
Yes or No
Muscatine Power and Water
Yes
Public Service Enterprise Group
Yes
Indiana Municipal Power Agency
Yes
Exelon and its' affiliates
Yes
MidAmerican Energy Company
Yes
Independent Electricity System
Operator
Yes
BrightSource Energy, Inc.
Yes
American Electric Power
Yes
Consumers Energy Company
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 3 Comment
71
Organization
Yes or No
Alliant Energy
Yes
Manitoba Hydro
Yes
Hydro-Quebec TransEnergie
Yes
Nebraska Public Power District
Yes
New York Power Authority
Yes
Omaha Public Power District
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
Volkmann Consulting, Inc
Yes
Consideration of Comments: Project 2010-17 | September 2013
Question 3 Comment
72
Organization
Yes or No
Tri-State Generation and
Transmission Association, Inc.
Yes
Xcel Energy
Yes
MRO
Yes
Hydro One
Yes
Question 3 Comment
American Transmission Company, Yes
LLC
First WInd
Yes
Minnkota Power Cooperative
Yes
Response: Thank you for your support.
Consideration of Comments: Project 2010-17 | September 2013
73
4. Are there any other concerns with this definition that haven’t been covered in previous questions and comments?
Summary Consideration: The proposed definition continues to include, through inclusion I4, individual dispersed power producing
resources if those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources
in a manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT is
retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the SDT’s
intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross
nameplate rating), and that are connected through a system designed primarily for delivering such capacity to a
common point of connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to
greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.
The SDT made the following changes to the white paper on the 50 kV threshold in response to suggestions made by commenters:
In this simplified depiction of a portion of an electric system, two radial 115 kV lines emanate from 115 kV substations A and B to
serve distribution loads via 115 kV distribution transformers at stations C and D. Stations C and D are “looped” together via either a
distribution bus tie (zero impedance) or a feeder tie (modeled with typical distribution feeder impedances).
The analyses determined the LODF which represents the portion of the high voltage transmission flow that would flow across the
low voltage distribution circuit or bus ties under a single contingency outage of the line between stations A and B.
Consideration of Comments: Project 2010-17 | September 2013
74
Organization
Yes or No
Dominion
No
Bonneville Power Administration
No
Duke Energy
No
Salt River Project
No
PacifiCorp
No
Question 4 Comment
Wisconsin Public Service Corporation No
Pepco Holdings Inc
No
Public Service Enterprise Group
No
Indiana Municipal Power Agency
No
Consideration of Comments: Project 2010-17 | September 2013
75
Organization
Yes or No
MidAmerican Energy Company
No
Independent Electricity System
Operator
No
Consumers Energy Company
No
Omaha Public Power District
No
City of Tallahassee
No
Volkmann Consulting, Inc
No
Tri-State Generation and
Transmission Association, Inc.
No
Xcel Energy
No
MRO
No
Consideration of Comments: Project 2010-17 | September 2013
Question 4 Comment
76
Organization
Yes or No
First WInd
No
Minnkota Power Cooperative
No
Public Utility District No.1 of
Snohomish County
No
Question 4 Comment
Response: Thank you for your review and comments.
Manitoba Hydro
Yes
(1) General Comment - replace “ Board of Trustees “ with “ Board of Trustees’ “
throughout the applicable documents/standards for consistency with other
standards.
Response: The SDT believes that the use of the apostrophe is appropriate if using the term in the possessive sense and will review
SDT documents for any instances of possessive use.
Seminole Electric Cooperative, Inc.
Yes
Consideration of Comments: Project 2010-17 | September 2013
(1) The definition utilizes the term “non-retail generation.” This term does not
appear to be clarified within the definition. However, the drafting team has
attempted to clarify the term in the guidance document. Unfortunately, the
guidance document is not final, meaning that it can be revised before being
finalized. Please define retail and non-retail generation as separate definitions
for inclusion into the Glossary contingent upon each other or make the BES
definition approval contingent on the guidance document being approved. See
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Exclusion E1(c).
(2) The terms “plant and facility” are not defined and are ambiguous. Please
provide quantitative and/or qualitative factors that an entity can utilize in
determining what is a plant/facility. See Inclusion I2.
(3) The following note will be placed in the Reference document:”Dispersed
power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an
alternative to, or an enhancement of, the traditional electric power system.”
Please strike the following language from the paragraph “or an enhancement
of,” as it is more of a persuasive statement than an objective statement.
(4) In Exclusion E1(c), please clarify that reactive devices, such as capacitor
banks, can be included in this section also. Reactive devices are differentiated
from real power devices in Inclusion I2 and so we request clarification that
reactive devices can be included in Exclusion E1(c).
(5) Inclusion I2 includes generation above 20 MVA/75MVA connected at 100 kV
or higher. However, the base definition includes all generation units
connected at 100 kV or higher. Units below 20 MVA/75MVA are never
actually excluded. The net effect is to include all generation under the base
definition regardless of size. To avoid future interpretation issues and ensure
consistency with the intent communicated in the Phase 1 guidance document
(page 13, Figure I2-6), Inclusion I2 needs to be written as an exclusion of units
less than 20 MVA/75 MVA. If this not the intent of I2, then the definition
needs to be modified to clarify the intent.
(6) Exclusion E2 currently states “: (i) the net capacity provided to the BES does
Consideration of Comments: Project 2010-17 | September 2013
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not exceed 75 MVA, and (ii) standby, back-up, and maintenance power
services...”. This statement could easily be covered under the section
currently labeled I2 and suggested above to be rewritten as an exclusion. We
would like to suggest potential language to simplify the definition, eliminate
inclusion I2 to ensure that units under 20 MVA/75 MVA are actually excluded
from the definition, and incorporate these ideas into exclusion E2 so that
Exclusion E2 would be:E2 - Generating resource(s) including the generator
terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above with: a) Gross individual nameplate rating less than
20 MVA. Or, b) Gross plant/facility aggregate nameplate rating less than 75
MVA. Or, c) One or more generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net
capacity provided to the BES does not exceed 75 MVA, and (ii) standby, backup, and maintenance power services are provided to the generating unit or
multiple generating units or to the retail Load by a Balancing Authority, or
provided pursuant to a binding obligation with a Generator Owner or
Generator Operator, or under terms approved by the applicable regulatory
authority.
(7) It would be extremely valuable for the team as part of any guidance
document to develop and review a decision tree supporting the definition and
include this decision tree in the next revision of the guidance document.
Response: 1. The SDT believes that the explanation provided in the Reference Document clarifies the term. Any revisions to the
Reference Document for Phase 2 will be completed by the SDT so consistency of intent and use will be accomplished. No change
made.
2. The SDT uses the terms plant and facility interchangeably as shown in the definition by the word structure ‘plant/facility’. The SDT
does not believe that this introduces ambiguity or confusion and that the examples shown in the Reference Document suffice to
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explain the terminology. No change made.
3. The SDT will consider this suggestion when the Reference Document is revised. No change made at this time.
4. Reactive devices are included in the BES if they fall under the criteria shown in Inclusion I5. No change made.
5. The SDT believes that Inclusion I2 correctly identifies what units are included in the BES and that stating the converse is
unnecessary and duplicative. No change made.
6. The SDT disagrees and believes that there are important distinctions and conditions shown in Exclusion E2 that warrant it being
treated separately. No change made.
7. The SDT believes that the hierarchical approach to the application of the definition that has been published in several documents,
including the Reference Document, fulfils the intent of the decision tree methodology suggested in the comment. As noted above,
the Reference Document will be revised after the Phase 2 definition is finalized, and the SDT will consider whether any additional
clarification would be helpful.
Idaho Power Company
Yes
1. In the wording for E3b (Local Networks), the phrase “and the LN does not
transfer energy originating outside the LN for delivery through the LN” does
not seem to add any value or specificity to the LN Exclusion. In fact, the phrase
seems misleading and serves to add confusion since some amount of energy
flowing in a parallel BES path outside the LN will always flow through the LN,
even if it’s just a trickle and does not impact the sign of the measured power
flow at the LN points of connection. Suggested reword for E3b is “Real power
flows only into the LN at each LN connection point.”
2. We agree that your clarifying single-line diagram for Inclusion I4 (40 - 2 MVA
generators aggregated up through the point of aggregation to the common
point of connection) for dispersed power producing resources properly
designates the point of aggregation of the dispersed power producing
resources as a BES element. We also agree with the basis for this designation
which states for the point of aggregation "where the individual generator
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nameplate ratings of the dispersed generation total > 75 MVA (actual 80 MVA)
and a single point failure would result in loss of all generation contained on the
dispersed generation site". However, following the same logic in basis, we do
not agree with the BES designation for each individual 2 MVA generator in your
clarifying single-line diagram. We think it makes sense that the reliability of the
power system should be considered for the loss of the 80 MVA and we agree
that a potential single point of failure exists at the point of aggregation that
could result in the loss of all generation. However, we do not think that the
loss of one 2 MVA generator would have any significant negative impact on the
reliability of the power system. If the loss of greater than 20 MVA via a single
point failure scenario is deemed significant to the reliability of the power
system (Inclusion I2, a), then that same logic suggests that each of the two
buses that aggregates 40 MVA of generation should be designated as BES. If,
on the other hand, due to the dispersed nature of the generation in the
clarifying single-line diagram, the loss of greater than 75 MVA via a single point
failure scenario is deemed significant to the reliability of the power system
(Inclusion I2, b), then that same logic suggests that the point of aggregation
that aggregates 80 MVA of generation should be designated as BES. No place
in the BES core definition nor in any of the inclusions (or exclusions) is there a
concern for the loss of 2 MVA of generation as having a negative reliability
impact on the power system. Therefore, we would not designate each
individual 2 MVA generator as BES as you have in your clarifying single-line
diagram and would suggest the following wording for Inclusion I2 for your
consideration:I2 - Generating resource(s) with: a) gross individual nameplate
rating greater than 20 MVA, including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100 kV or
above or,b) the point of aggregation of gross plant/facility with aggregate
nameplate rating greater than 75 MVA, including the system designed
primarily for delivering the aggregated capacity from the point where the
Consideration of Comments: Project 2010-17 | September 2013
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resources aggregate to greater than 75 MVA to a common point of connection
at a voltage of 100 kV or above.I4 - DELETED
Response: 1. The SDT disagrees and re-iterates its position that any flow out of a local network disqualifies it for Exclusion E3. This
point has been consistently presented by the SDT as one of the basic tenets for a local network and was explained in the white paper
published in Phase 1
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_definition_technical_
justification_local_network_20110819.pdf). No change made.
2. The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if those
resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a manner
that is comparable to other non-dispersed power producing resources and is an approach that was accepted and emphasized by the
Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power producing
resources; however, none of the options explored provided an equal and effective approach to address the Commission’s reliability
concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through clarification
of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT is retaining
Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
NAGF Standards Review Team
Yes
Consideration of Comments: Project 2010-17 | September 2013
1. The language of the proposed BES definition is rather convoluted and is
therefore difficult to apply correctly without the Reference Document. The
FERC order 773/773a-amended Reference Document is not complete or final
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for the phase-2 BES definition, however. Its exclusion E1 statement is that of
phase-1, not phase-2, for example, and a disclaimer on p.1 states “...this
reference document is outdated. Revisions to the document will be developed
at a later date to conform to the definition being developed in Phase 2.” It
appears that the phase-2 BES definition is being rushed through the approval
process, and it would be preferable to take the time to compile a complete and
consistent body of documentation before putting the matter up for a vote. This
is especially important for correctly classifying very small, standby, nonBlackstart Resource gensets feeding the aux buses of generation plants for
emergency purposes. Such emergencies include blackouts and max-generation
situations, and in the latter case displacing some of the aux load can
temporarily boost the net amount of power delivered by the plant.
2. Figure I2-5 of the Reference Document suggests that such standby
generators are part of the BES, if the plant totals more than 75 MVA, because
they "contribute to the gross aggregate rating of the site." Fig. I2-5 depicts all
units exporting to the grid, however, and we are considering here only standby
gensets feeding aux buses that remain net importers of power. Exclusion E3
may apply, however. Fig. S1-9b of the Reference Document shows a system
composed of several generating plants and users, but the conclusions reached
by the SDT should be unchanged if one drew a box around the diagram and
labeled it a single generating plant. Specifically, the SDT decided that Exclusion
3 is invoked by the circumstance that the bus fed by the 5 MVA generator at
lower left is exclusively an importer of power, and this ruling should apply as
well for standby gensets that feed aux buses within generation plants. Making
such a classification would require that a Local Network (LN) can exist within a
generation plant, as opposed be being found exclusively in the systems of TOs
and DPs. Such an interpretation may be permitted by the circumstance that
the definition of an LN uses the word "transmission" with a lower-case "t", as
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opposed the TO and DP-oriented term "Transmission" in the NERC Glossary,
but the LN definition also references serving "retail customer load." This
definition should be changed, or (better) the BES definition should explicitly
state that gensets < 20 MVA feeding power-importing aux buses of generation
plants are excluded from the BES.
The term "nameplate rating" should be replaced by the NERC-defined term
"Facility Rating" to harmonize the BES definition with NERC’s standards.
3. Inclusion I2a should be deleted and I2b should be used to define the
threshold for all generating facilities. It is inconsistent to include a 21 MVA
single generator (using I2a) and not include 74.5 MVA aggregated
conglomeration of individual generators (using I2b). Since 75MVA is used as
the threshold in multiple places in this definition, a single generator unit
(Facility Rating) at 75 MVA connected at > 100kV should be the individual unit
size threshold.
4. Please specify what size of reactive power resources is included by I5 (>
75MVAR?).
PPL NERC Registered Affiliates
Yes
Consideration of Comments: Project 2010-17 | September 2013
a. The language of the proposed BES definition is somewhat vague and is
therefore difficult to apply correctly without the Reference Document. The
FERC order 773/773a-amended Reference Document is not complete or final
for the phase-2 BES definition, however. Its exclusion E1 statement is that of
phase-1, not phase-2, for example, and a disclaimer on p.1 states that “...this
reference document is outdated. Revisions to the document will be developed
at a later date to conform to the definition being developed in Phase 2.” It
appears that the phase-2 BES definition is being rushed through the approval
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Organization
Yes or No
Question 4 Comment
process, and it would be preferable to take the time to compile a complete and
consistent body of documentation before putting the matter up for a vote. This
is especially important for correctly classifying very small, standby, nonBlackstart Resource gensets feeding the aux buses of generation plants for
emergency purposes. Such emergencies include blackouts and max-generation
situations, and in the latter case displacing some of the aux load can
temporarily boost the net amount of power delivered by the plant. Figure I2-5
of the Reference Document suggests that such standby generators are part of
the BES, if the plant totals more than 75 MVA, because they "contribute to the
gross aggregate rating of the site." Fig. I2-5 depicts all units exporting to the
grid, however, and we are considering here only standby gensets feeding aux
buses that remain net importers of power. Exclusion E3 may apply, however.
Fig. S1-9b of the Reference Document shows a system composed of several
generating plants and users, but the conclusions reached by the SDT should be
unchanged if one drew a box around the diagram and labeled it a single
generating plant. Specifically, the SDT decided that Exclusion 3 is invoked by
the circumstance that the bus fed by the 5 MVA generator at lower left is
exclusively an importer of power, and this ruling should apply as well for
standby gensets that feed aux buses within generation plants. Making such a
classification would require that a Local Network (LN) can exist within a
generation plant, as opposed be being found exclusively in the systems of TOs
and DPs. Such an interpretation may be permitted by the circumstance that
the definition of an LN uses the word "transmission" with a lower-case "t", as
opposed the TO and DP-oriented term "Transmission" in the NERC Glossary,
but the LN definition also references serving "retail customer load." This
definition should be changed, or (better) the BES definition should explicitly
state that gensets < 20 MVA feeding power-importing aux buses of generation
plants are excluded from the BES.
Consideration of Comments: Project 2010-17 | September 2013
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b. The term "nameplate rating" should be replaced by the NERC-defined term
"Facility Rating" to harmonize the BES definition with NERC’s standards.
c. Inclusion I2a should be deleted and I2b should be used to define the
threshold for all generating facilities. It is inconsistent to include a 21 MVA
single generator (using I2a) and not include 74.5 MVA aggregated
conglomeration of individual generators (using I2b). Since 75MVA is used as
the threshold in multiple places in this definition, a single unit (facility rating) at
75 MVA connected at > 100kV should be the individual unit size threshold.
d. Please specify what size of reactive power resources is included by I5 (>
75MVAR?).
Associated Electric Cooperative, Inc.
- JRO00088
Yes
Consideration of Comments: Project 2010-17 | September 2013
AECI supports the NAGF's draft comment for concern, duplicated immediately
below:"The language of the proposed BES definition is rather convoluted and is
therefore difficult to apply correctly without the Reference Document. The
FERC order 773/773a-amended Reference Document is not complete or final
for the phase-2 BES definition, however. Its exclusion E1 statement is that of
phase-1, not phase-2, for example, and a disclaimer on p.1 states that “...this
reference document is outdated. Revisions to the document will be developed
at a later date to conform to the definition being developed in Phase 2.” It
appears that the phase-2 BES definition is being rushed through the approval
process, and it would be preferable to take the time to compile a complete and
consistent body of documentation before putting the matter up for a vote. This
is especially important for correctly classifying very small, standby, nonBlackstart Resource gensets feeding the aux buses of generation plants for
emergency purposes. Such emergencies include blackouts and max-generation
situations, and in the latter case displacing some of the aux load can
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Question 4 Comment
temporarily boost the net amount of power delivered by the plant. Figure I2-5
of the Reference Document suggests that such standby generators are part of
the BES, if the plant totals more than 75 MVA, because they, "contribute to the
gross aggregate rating of the site." Fig. I2-5 depicts all units exporting to the
grid, however, and we are considering here only standby gensets feeding aux
buses that remain net importers of power. Exclusion E3 may apply, however.
Fig. S1-9b of the Reference Document shows a system composed of several
generating plants and users, but the conclusions reached by the SDT should be
unchanged if one drew a box around the diagram and labeled it a single
generating plant. Specifically, the SDT decided that Exclusion 3 is invoked by
the circumstance that the bus fed by the 5 MVA generator at lower left is
exclusively an importer of power, and this ruling should apply as well for
standby gensets that feed aux buses within generation plants. Making such a
classification would require that a Local Network (LN) can exist within a
generation plant, as opposed be being found exclusively in the systems of TOs
and DPs. Such an interpretation may be permitted by the circumstance that
the definition of an LN uses the word "transmission" with a lower-case "t", as
opposed the TO and DP-oriented term "Transmission" in the NERC Glossary,
but the LN definition also references serving "retail customer load." This
definition should be changed, or (better) the BES definition should explicitly
state that gensets < 20 MVA feeding power-importing aux buses of generation
plants are excluded from the BES. Additionally, the MVA size of reactive power
generator that is included by I5 should be specificed."
Response: 1. The SDT has not published a Phase 2 Reference Document at this time and did not intend the posted version to
represent a full implementation of Phase 2 as Phase 2 isn’t complete. A revised Reference Document will be published in the same
timeframe and sequence that was used in Phase 1. The SDT is following the established development process and while working
against a deadline is not rushing things through. No change made.
2. The identified equipment exists today and precedent has already been established as to how to handle it with regard to BES
Consideration of Comments: Project 2010-17 | September 2013
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inclusion. Nothing in the proposed definition changes this. The intent of the SDT is that the precedent will not change how the
identified equipment is classified. The intent of the SDT is to identify BES generators and it believes that the current language is
clear in that regard. No change made.
The SDT believes that nameplate rating is the correct term to use in a bright-line definition. Facility Rating is a variable value that
would cause the determination of whether units are BES or not to fluctuate from period to period making for an untenable
compliance situation. No change made.
3. The SDT is following the recommendation of the Planning Committee in its report on threshold values
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fi
nal_20130306.pdf) in the retention of the 20 and 75 MVA threshold values. No change made.
4. All reactive power devices are included by Inclusion I5 regardless of size as recommended by the Planning Committee in the
report cited in response 3.
Ameren
Yes
1. We request the SDT to provide clarification for E3b testing conditions,
specifically for all facilities in service or for single transmission contingency
conditions. We believe that the criteria needs to be very clear so it is not
confusing for entities when determining inclusion of local network facilities as
BES facilities.
2. Also, we do not believe that 1 MW of back-feed from local network facilities
to transmission facilities for a few hours out of the year constitutes
classification of the local network facilities as BES facilities. We request that
the SDT consider for inclusion that the magnitude of the injections from the
local network should be in line with other injections into the transmission
system such as: (a) Generators with a nameplate greater than 20 MVA, or (b)
Aggregate resources greater than 75 MVA.
3. In our opinion, the standard puts additional burden on local network
owners including local subtransmission network owners to prove that their
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facilities should be excluded from consideration as BES facilities. (a) We
believe that, testing for BES inclusion could be included in the annual TPL
contingency analysis, but it may not be possible to complete this type of
analysis before the end of the year unless the criteria is clearly defined and
limited in scope, otherwise numerous models reflecting varying system
conditions would need to be considered. (b) We ask the SDT to recall that it
was suggested in the last webinar that SCADA data could be used to prove that
there was no back-feed from the local network to the transmission system. (c)
We realize that the accuracy of SCADA data at low flow levels can be suspect at
low load flows but if considered with the type of relaying, that is if the relaying
limits power flow back into the BES transmission system, this could be used as
a means of quick determination for inclusion.
We appreciate the work of the SDT effort to provide a reasonable and balanced
approach to the determination of BES facilities, and doing all of this within a
very short period of time. Again we ask the SDT for consideration with respect
of the 50kV threshold being raised to 70kV, and that with respect to injections
into the transmission network from the various generation and local network
sources that they be considered as a comparable basis in the determination of
BES facilities.
SERC Planning Standards
Subcommittee
Yes
Consideration of Comments: Project 2010-17 | September 2013
E3b: The testing conditions for E3b should be clearly stated, namely for all
facilities in service or for single transmission contingency conditions. We
believe that the criteria need to be anchored so as not to manufacture a
justification for inclusion of local network facilities as BES facilities. Add word
“normally” between “not” and “transfer” to E3b: Real Power flows only into
the LN and the LN does not normally transfer energy originating outside the LN
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for delivery through the LN; and
We do not believe that 1 MW of back-feed from local network facilities to
transmission facilities for a few hours of the year constitutes classification of
the local network facilities as BES facilities. We believe that the magnitude of
the injections from the local network should be reviewed in line with other
injections into the transmission system such as a) generators with a nameplate
greater than 20 MVA, or b) aggregate resources greater than 75 MVA.
In our opinion, the standard puts additional burden on local network owners
including local subtransmission network owners to prove that their facilities
should be excluded from consideration as BES facilities. In theory, this testing
could be included in the annual TPL contingency analysis, but it may not be
possible to complete this type of analysis before the end of the year for
numerous models reflecting varying system conditions. It was suggested in the
last webinar that SCADA data could be used to prove that there was no backfeed from the local network to the transmission system, but the accuracy of
some SCADA data at low flow levels can be suspect and the SCADA data does
not identify the exact system conditions that were experienced when the
SCADA measurements were recorded, including outages to local
subtransmission facilities.
We appreciate the work of the SDT to try and provide a reasonable and
balanced approach to the determination of BES facilities, and within a very
short period of time. We ask that the injections into the transmission network
from the various generation and local network sources be considered on a
comparable basis in the determination of BES facilities.
The comments expressed herein represent a consensus of the views of the
Consideration of Comments: Project 2010-17 | September 2013
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above named members of the SERC PSS and 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.
Response: 1. The SDT has been clear from the beginning that local networks must meet the criteria of Exclusion E3 for all operating
conditions. No change made.
2. The position of the SDT has consistently been that local networks that have flow back into the BES at any time do not qualify
under exclusion E3 as a local network. In the Reference Document, the SDT proposed a method to measure this factor so that a brief
momentary fluctuation will not negate the ability to invoke Exclusion E3. No change made.
3. The SDT has always proposed that SCADA data could be used to determine local network applicability.
4. The commenter has presented no technical rationale for increasing the threshold value above 50 kV. The studies performed by
the SDT indicate that 50 kV is the highest supportable threshold value, i.e., where the loop configuration starts to flow back to the
BES and may be considered necessary for the reliable operation of the interconnected transmission system. No change made.
Southern Company
Yes
A) Inclusion I2a should be deleted and I2b should be used to define the
threshold for all generating facilities. It is inconsistent to include a 21 MVA
single generator (using I2a) and not include 74.5 MVA aggregated
conglomeration of individual generators (using I2b). Since 75 MVA is used as
the threshold in multiple places in this definition, a single generator at 75
connected at > 100kV should be the individual unit size threshold.
B) Please specify what size of Reactive Power resources is included by I5.
Order 773 acknowledged that Inclusion I5 is the technical equivalent of
Inclusion I2 (generating resources) for reactive power devices. Since
generating resources in Inclusion I2 are limited to those connected at 100kV or
above with individual and aggregate ratings of 20MVA and 75 MVA,
respectively, it could be consistent -- if technically justified -- to include a
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threshold of >75MVAR for reactive power resources. Some technical
justification should be pursued to determine whether 75 MVAR or a different
size threshold would be appropriate to include in Inclusion I5 for Reactive
Power resources.
C) Southern Transmission believes that Exclusion E3 should include a limit on
the size of a Local Network (LN). This position is consistent with the proposal
from the NERC System Analysis and Modeling Subcommittee (SAMS). Without
placing a size limitation on such a network, a single contingency could result in
significant flows across the BES to serve the LN from a different location. The
SAMS provided technical justification for a 300 MW load limit and Southern
would be supportive of such a limit. Southern also agrees with the SAMS that
the flow should be into the LN under single contingency conditions. (See
NERC’s Review of Bulk Electric System Definition Thresholds, March 2013,
Section 5.3)
D) Southern believes that the second part of Exclusion E3 should be deleted for
three reasons: First, Exclusion E3a refers to “non-retail generation”. Southern
believes that whether a unit is “retail” or “non-retail” should be irrelevant
when determining inclusion in the BES. Regardless of how a generator is
classified, if it is large enough to impact flows on the system, then it should be
included in the BES. Second, the phrase “and do not have” in the second
phrase of Exclusion E3a is ambiguous and redundant and could lead to
confusion and misapplication. Specifically, it is ambiguous as to whether the
last phrase regarding aggregate non-retail capacity:(a) refers back to the
generation resources identified in Inclusion I2, I3, or I4 (thus defining a smaller
subset of generation resources from I2, I3, and I4 that are carved out from the
definition of LN, but other Inclusion I2-I4 generation resources can be part of
the local network); or(b) simply refers back to “generation resources”
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(therefore, local networks exclude BOTH Inclusion I2-I4 generation resources
AND, separately, generation resources with aggregate non-retail generation
>75MVA).Third, Inclusions I2 and I4 already both use the 75 MVA limit. It
seems redundant to state that a Local Network under Exclusion E3a does not
include generation resources with aggregate capacities greater than 75 MVA
when Exclusion E3a already states that local networks do not include
generation resources identified in Inclusion I2 and I4 (which, in turn, include
generation resources with aggregate capacities above 75 MVA). To clarify and
to eliminate confusing and unnecessary redundancy, Southern suggests striking
all language after “Inclusion I4.” Exclusion E3a should therefore read: “a) Limits
on connected generation: The LN and its underlying Elements do not include
generation resources identified in Inclusions I2, I3, or I4.”
Response: a. The SDT is following the recommendation of the Planning Committee in its report on threshold values
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fi
nal_20130306.pdf) in the retention of the 20 and 75 MVA threshold values. No change made.
b. All reactive power devices, regardless of size, are included by Inclusion I5 as recommended by the Planning Committee in the
report cited in response a.
c. The SDT does not believe that such a limit is needed. In the example provided, the SDT sees no affect on the reliability of the BES
simply because a configuration of equipment has been designated as a local network. Further, evaluating local network applicability
under planning scenarios such as single contingency operation violates the bright-line principle of the definition. No change made.
d. The differentiation between retail and non-retail is based on Exclusion E2 and the SDT believes that such differentiation is
warranted in Exclusion E3. There is a difference in citing individual units or aggregation of units under Inclusion I2 and a 75 MVA limit
as expressed in Exclusion E3a. The 75 MVA limit was retained to capture the situation where there are multiple plants/facilities
within the local network that might add up to 75 MVA but which wouldn’t be captured under inclusion i2. No change made.
Consideration of Comments: Project 2010-17 | September 2013
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Question 4 Comment
Alliant Energy
Yes
Alliant Energy reiterates that Inclusion I4a must be removed from the
definition of the BES. It makes no technical sense, and creates an extremely
burdensome compliance workload and risk.
Madison Gas and Electric Company
Yes
The inclusion of I4a does not support the reliabile operation of the BES. As
stated before, we agree that the point of interconnection should be included,
not the individual intermitent resources.
BANC & SMUD
During Phase-1, it was suggested that a 75 MVA threshold be established where the loss of a
single element would render the entire 75 MVA of resources unavailable. This was in lieu of
including the individual small-scaled machines as BES to avoid subjecting those machines to
administrative burden for little or no impact on the BES as compared to the compliance
obligation. (Please refer to response to Q2 for additional details.)
Response: The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating),
and that are connected through a system designed primarily for delivering such capacity to a common point of connection at
Consideration of Comments: Project 2010-17 | September 2013
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Organization
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Question 4 Comment
a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
NIPSCO
Yes
Another major concern is whether our 138 kV industrial customers with
multiple feeds are part of the BES. One of the criteria is whether power ever
flows through the customer's system. This could be very difficult to prove with
evidence. Perhaps during the last year's peak load or maximum transfer across
the host TOP's system, the flow could be integrated over an hour; if there is
system flow across the customer's system during the integrated hour, then the
customer's system should be considered part of the BES and the customer
should have multiple years to comply with becoming part of the BES.
If the customer becomes part of the BES would this mean that they would have
to become a TO/TOP? Would it require that they have NERC certified
operators? We see these as emerging concerns.
Additionally, it appears that several small wind generators may become part of
the BES which would bring PRC-004 misoperations into play for them. It is our
understanding that such generators trip off line based on wind and wind
direction. Keeping track of these operations and the associated analysis may
become quite an undertaking. Other standards such as PRC-005 may also
become a concern.
Response: The SDT can’t respond to individual requests for determination of whether a specific configuration is BES or not.
However, in the Reference Document, the SDT did supply a mechanism for measuring flow that did involve integrated hourly values.
Consideration of Comments: Project 2010-17 | September 2013
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Question 4 Comment
Similarly, the SDT can’t make a determination on registration issues or the need for certified operators.
The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if those
resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a manner
that is comparable to other non-dispersed power producing resources and is an approach that was accepted and emphasized by the
Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power producing
resources; however, none of the options explored provided an equal and effective approach to address the Commission’s reliability
concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through clarification
of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT is retaining
Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating),
and that are connected through a system designed primarily for delivering such capacity to a common point of connection at
a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
American Transmission Company,
LLC
Yes
Consideration of Comments: Project 2010-17 | September 2013
ATC has the following additional comment for consideration by the SDT: o
Exclusion 3b does not currently define the limited set of conditions entities are
to consider when determining if real power flows only into the local network
(LN). Without this clarification, entities will have no certainty regarding the
exclusion determination made, which can have a material impact on the entity
under all of the NERC standards. ATC recommends the following revision to
E3b:E3b) Real Power flows only into the LN under intact system and most
severe single contingency conditions and the LN does not transfer energy
originating outside the LN for delivery through the LN; and’ This revision is
warranted for the reason noted above. In addition, the language is consistent
with how the system is operated under the NERC TOP standards and the
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proposed addition matches NERC’s own statements to the FERC as recorded in
paragraph 71 of FERC Order 773-A. As noted in the same paragraph, FERC
agreed with NERC’s reasoning. Therefore, this clarification should be recorded
in the BES definition.
Response: The SDT has consistently indicated its intent that local networks must meet the criteria of Exclusion E3 for all operating
conditions. No change made.
Modesto Irrigation District
Yes
I voted NO for the following reasons:1. WECC studies have shown that there
are thousands of MWs of wind and PV generating plants currently on-line, and
thousands of MWs under development, in the WECC system, of 20 MW and
less capacity units. Ignoring the impacts of these units on the BES would be a
mistake, as recent studies by the WECC MVWG (Modeling and Validation Work
Group) have shown (i.e., June 2013 Meeting).
2. The revisions have made the definition of the BES so complicated, that the
definition is no longer in a form that can be applied in a straight forward and
reasonable manner. Also, there are no technical justifications provided for
some of the exclusion criteria (e.g, 75 MVA ).
3. The best way to define the BES is by using the engineering methodology
developed by the WECC BES Definition Task Force, and published in May 2010.
That study work showed that for the location in question to have a material
impact to the interconnected bulk electric power system, there must be an
equivalent short circuit MVA exceeding 6000 at that location.Thank you.
Response: 1.The SDT is not proposing to ignore the impact of wind and PV generation but to arrive at the optimal solution for
achieving over-all BES reliability. The SDT is also attempting to achieve a bright-line definition of BES. If there are some units that
Consideration of Comments: Project 2010-17 | September 2013
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fall ‘outside’ of the bright-line that a reliability entity feels should be part of the BES that entity always has the option to file for an
inclusion to the BES through the established exception process. No change made.
2. The SDT is following the recommendation of the Planning Committee in its report on threshold values
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fi
nal_20130306.pdf) in the retention of the 20 and 75 MVA threshold values. No change made.
3. As stated in the FERC Orders, material impact alone is not a sufficient condition for determining BES applicability. The revised
“bright-line” definition developed under the Phase 1 project was approved by the industry and the Board of Trustees. No change
made.
Hydro-Quebec TransEnergie
Yes
HQT's position remains the same concerning the BES Definition, as limitations
on exclusion are increased in phase 2 as imposed by FERC without proper
hearing of non-US jurisdictions.
One other comment on the Implementation plan refers to the second sentence
of Effectives dates. The second sentence should be arranged differently as it
refers both to "no regulatory approval required" and "applicable governmental
authorities". The last part of the sentence should be moved with the first
sentence to add clarity.
Hydro One
Yes
Consideration of Comments: Project 2010-17 | September 2013
In Canada, local load reliability requirements are under the provincial authority
of local regulators such as the Ontario Energy Board in Ontario. We
understand that NERC needs to follow FERC Orders and directives. In our
opinion NERC must ensure that any provisions within the BES definition and/or
NERC standards that are to address load reliability and load supply continuity
issues and NOT interconnected BES reliability should be limited to the FERC
jurisdiction only. Accordingly we suggest that when addressing such
requirements in a standard it must include that for a non-US Registered Entity
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it should be implemented in a manner that is consistent with, or under the
direction of, the applicable governmental authority or its agency in the non-US
jurisdiction. Good examples to address these issues are through the Standards
process as was done for NUC 001 and TPL001 Footnote b.
Northeast Power Coordinating
Council
Yes
Suggest the following rewording of the Effective Dates section of the
Implementation Plan to add clarity regarding approvals: In those jurisdictions
where no regulatory approval is required the definition shall become effective
on the first day of the second calendar quarter after Board of Trustees
adoption, or as otherwise made effective pursuant to the laws of applicable
governmental authorities. In those jurisdictions where no regulatory approval
is required the definition shall (go should be deleted) become effective on the
first day of the second calendar quarter after Board of Trustees adoption.
NPCC participating members suggest that when addressing the requirements
pertaining to load reliability and continuity in a standard, they must include
that for a non-U.S. Registered Entity it should be implemented in a manner
that is consistent with, or under the direction of, the applicable governmental
authority or its agency in the non-U.S. jurisdiction.
Response: The revised definition project was undertaken in response to a FERC Order but provides an appropriate continent-wide,
bright-line for reliability of the BES based on physical principles and demonstrated in the technical analysis in the white paper
supporting the selection of the 50 kV threshold
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_white_paper
_sub100kv_threshold_20130802.pdf). Therefore, the SDT sees no reason for a reference to non-US Registered Entities. No change
made.
Consideration of Comments: Project 2010-17 | September 2013
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SPP Standards Review Group
Yes
Question 4 Comment
In the Implementation Plan, delete ‘go’ at the beginning of the 3rd line of the
1st paragraph.
WhitepaperOn Page 9, Line 9 of the 1st paragraph, delete the ‘/’.
On Page 9, Line 3 of the 2nd paragraph, replace ‘represent’ with ‘represents’.
On Page 9, Line 4 of the 2nd paragraph, replace ‘distribute’ with ‘flow’.
Response: The SDT agrees with your correction to the Implementation Plan language; however, that language has been revised to
reflect different approaches to making standards enforceable in various Canadian jurisdictions.
The SDT agrees and has made the suggested change to the white paper.
Arizona Public Service Company
Yes
Inclusion I5 is about reactive sources. However it only excludes E4. There is no
reason why all exclusions E1 to E4 should not apply to reactive sources. The
current definition will include reactive sources in radial system as part of BES.
There is no technical reason for excluding radial system and yet including
reactive sources in radial system as part of BES
Response: The SDT is following the recommendation of the Planning Committee in its report on reactive devices
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fi
nal_20130306.pdf) where the Planning Committee recommended that all reactive devices be included in the BES. No change made.
Nebraska Public Power District
Yes
Consideration of Comments: Project 2010-17 | September 2013
It is imperative to have the BES reference document be updated to reflect the
latest changes and drafting team position on various items with the definition
since the definition is not self-explanatory due to the significant BES system
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variations. Perhaps some additional examples with low voltage looped systems
would be beneficial similar to the scenarios noted in question 2 above.
We also have concerns with the disclaimer in the reference document on page
1 and noted below. We would hope this document would be endorsed by
NERC to help address the complexity of the definition and to aid in
transparency.”Disclaimer-This document is not an official position of NERC and
will not be binding on enforcement decisions of the NERC Compliance
Program. This reference document reflects the professional opinion of the
DBES SDT, given in good faith for illustrative purposes only.”
Response: The SDT will be updating the Reference Document to reflect Phase 2 as soon as possible.
The Reference Document can only reflect the intent of the SDT and isn’t a legal document. No change made.
NARUC
Yes
NARUC shares the concern raised by New York about the Phase II Report’s
failure to meet its purported goal of providing a technical justification for
100kV bright line rule and generation thresholds. NY raised specific concerns
about a survey not being appropriate technical support for specific numbers
and the drafting team did not specifically address this, or other concerns raised
about the technical justification, in its response.
NARUC is also concerned that the methodology utilized historically by the
NPCC was not considered as one of five alternatives. So in response to
whether or not there are other concerns with this definition that have not
been covered in previous questions and comments, NARUC notes that it shares
these concerns that have been raised, as well as the lack of a response from
the drafting team thus far and requests a thorough response.
Consideration of Comments: Project 2010-17 | September 2013
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Yes or No
New York State Department of
Public Service
Yes
Question 4 Comment
NERC has an obligation to provide technical advice to FERC, so that any number
provided to FERC by NERC is interpreted as technical advice. A major purpose
of the BES Phase II effort was to establish a technical basis for the 100 kV
brightline and the 20/75 MVA generation levels. While NERC has provided a
report purportedly providing a technical basis for these threshold levels, the
report fails to do so. NERC should not include any numbers in any definition or
standard for which it cannot provide a technical basis. Surveys do not provide a
technical basis. Particularly troublesome is the presentation of alternatives to
the 100 kV brightline. The report authors looked at 5 alternatives to
establishing a technical basis for determining the bulk system.
The report failed to evaluate the methodology historically applied to the NPCC
system. If a major NERC region was able to successfully apply their
methodology, why was it not evaluated and why would it be impossible to
expect other regions to perform a similar analysis as the base for determining
the BES? This comment is being resubmitted as the response provided in the
previous comment period does not address the issues raised.
Response: The SDT is following the recommendation of the Planning Committee in its report on threshold values
(http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fi
nal_20130306.pdf) in the retention of the 20 and 75 MVA threshold values as well as the 100 kV bright-line. No change made.
The methodology applied by NPCC was rejected by FERC in its Order on the BES definition. No change made.
Exelon and its' affiliates
Yes
Consideration of Comments: Project 2010-17 | September 2013
Suggest adding the following to E4: or for the sole purpose of regulating
internal generating station auxiliary buses. So that it reads: E4 - Reactive Power
devices installed for the sole benefit of a retail customer(s) or for the sole
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purpose of regulating internal generating station auxiliary buses.
Response: The SDT believes that if a reactive device is installed for the sole purpose of regulating internal generating station
auxiliary buses that the device has been installed for the sole benefit of a retail customer and therefore the suggested language is
not necessary. No change made.
New York Power Authority
Yes
Support the development of a SAR that will create a project to review all of the
GO and GOP standards for effective applicability to dispersed power resources
so that generator owners and operators are only subject to the Standards
requirements that have reliability impacts and those standard requirements
that are applicable to the generator type.
Response: Any entity is free to develop a SAR to address areas of concern.
Muscatine Power and Water
Yes
The SDT has recommended that a SAR be submitted in order to refine the
Standards that would be applicable to individual power producing resources
contained under I4 of the phase II definition. This response is not acceptable.
The SDT should not passively answer an entity's question by stating that a
different process "may" fix the issue at hand.
MP&W recommends I4a be deleted and I4b be maintained as I4a. I4a should
be deleted in its entirety. The SDT is forcing every dispersed power Facility
over 75 MVA to be in the definition, where the SDT should be keeping
individual resources out and allow other Standards and SDTs to determine if
that should be included within each individual Standard. The BES definition
should be written to give broad details and each individual Standard should be
where the details are maintained. This is already the case for the following
Standards; MOD-025-1, R1 and VAR-001-2, R3 are two examples where the
Consideration of Comments: Project 2010-17 | September 2013
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Standard dictates what is applicable and what is not. MP&W does not believe
that since FERC has approved Phase I that the SDT is bound by that approval as
being unchangeable. The Commission has only approved a part of the process
and no where is it stated that once Phase I is approved that it can not be
changed. This is proof with the other changes that the SDT has made in Phase
II compared to Phase I. NERC or the SDT have not provided the industry with
event analysis or lessons learned information that an individual dispersed
power producing resource within a Facility has led to instability or cascading
events on the BES. The inclusion of I4a does not align itself with the current
NERC and Regional RAI process. NERC's CEO and President has even said that
everything cannot be a priority. The amount of records management will only
benefit a consultant who sells their services in managing individual power
producing resources (i.e. paper work). The Registered Entity and their Region
will not see the benefit of tracking several thousand wind turbines and solar
panels, for what? The "what" is unknown because the SDT is taking words of
the "Statement of Compliance Registry Criteria" and applying it to our
standards development process. Currently Entities do not register per Facility,
but this definition does force entities to register per Facility. The SDT is mixing
apples and oranges.
Response: Applicability of individual standards is not within the scope of this SDT. A new SAR specifically tailored to address this
presumed problem is the correct method to alleviate these concerns.
The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if those
resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a manner
that is comparable to other non-dispersed power producing resources and is an approach that was accepted and emphasized by the
Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power producing
resources; however, none of the options explored provided an equal and effective approach to address the Commission’s reliability
concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through clarification
of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT is retaining
Consideration of Comments: Project 2010-17 | September 2013
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Question 4 Comment
Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating),
and that are connected through a system designed primarily for delivering such capacity to a common point of connection at
a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
American Electric Power
Yes
To reiterate, AEP does not agree with the premise that BES elements
(measured for compliance) should be as granular as the individual dispersed
power resource. We do not see the reliability benefit of tracking all of the
compliance elements for individual wind turbines when the focus should be
placed on the aggregate of the facilities. Does the RC want to be notified of an
outage of each individual wind turbine in real-time, or a loss of significant
portion of the wind farm? If we are not careful, we will have entities at these
resources and others monitoring them (BAs, TOPs, RCs) focusing on minor
issues that will distract from more relevant reliability needs. We appreciated
the development of the diagram to explain the scenario. We encourage the
team to continue to provide these illustrations to clarify the intent and the
application.
When the guidance documents were produced last year, we had a better
understanding of how the pieces of the definition fit together (and where there
were significant gaps). We encourage the SDT to develop the scenarios and
the diagrams first for industry review then the definition should be crafted to
meet those.
Consideration of Comments: Project 2010-17 | September 2013
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Question 4 Comment
We understand the pressure to meet the FERC deadlines, but continuing to
tweak this foundation little by little had proved to be a difficult task and an
overhaul of the approach might yield better results. If this requires modifying
the SAR to provide the SDT with the flexibility to address broader concerns,
AEP endorses this approach.
Response: The proposed definition continues to include, through inclusion I4, individual dispersed power producing resources if
those resources aggregate to a total value greater than 75 MVA. This inclusion treats dispersed power producing resources in a
manner that is comparable to other non-dispersed power producing resources and is an approach that was accepted and
emphasized by the Commission in Orders No. 773 & 773-A. The SDT has explored various options associated with dispersed power
producing resources; however, none of the options explored provided an equal and effective approach to address the Commission’s
reliability concerns with these facilities. The SDT continues to believe that the best resolution to the industry’s concerns is through
clarification of the applicability of individual Reliability Standards and not a revision to the BES definition. Given these facts, the SDT
is retaining Inclusion I4a but has revised the language of inclusion I4, based on industry comments, to provide greater clarity of the
SDT’s intent.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and
that are connected through a system designed primarily for delivering such capacity to a common point of connection at a
voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than
75 MVA to a common point of connection at a voltage of 100 kV or above.
The Reference Document will be revised to reflect Phase 2 as soon as possible.
Any entity is free to develop a SAR to address areas of concern.
Transmission Access Policy Study
Yes
Consideration of Comments: Project 2010-17 | September 2013
We suggest that the SDT clarify, either in the definition itself or in the
reference document, that a momentary flow-through caused by an
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Question 4 Comment
abnormal/contingency condition does not make a system ineligible for
Exclusion E3. TAPS members are willing to work with the SDT on defining
appropriate limits for such minimal, momentary flow-throughs.
Response: The position of the SDT consistently has been that local networks that have flow back into the BES at any time do not
qualify under exclusion E3 as a local network. In the Reference Document, the SDT proposed a method to measure this factor so
that a brief momentary fluctuation will not negate the ability to invoke Exclusion E3. No change made.
ACES Standards Collaborators
Yes
We understand that NERC has developed a process for handling exception
requests. We are concerned this process could be similar to the TFE exception
process. We recommend that the exception process should be included with
future BES definition postings with the opportunity to comment on the
process.
Response: The exception process was posted for review and comment during Phase 1 of the project. It was approved by the
industry, the Board of Trustees, and FERC. No changes have been made or are expected to be made to this process during Phase 2.
If changes are needed to this process in the future, they will be posted for review and comment as per the established procedures.
*Figure submitted by Tri-State G&T referenced in Q1 comments:
http://www.nerc.com/pa/Stand/Documents/BES_I4_Clarification_for_Included_Elements_09042013.pdf
END OF REPORT
Consideration of Comments: Project 2010-17 | September 2013
107
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
Proposed Action Plan and Description of Current Draft:
This draft is the third comment posting and successive ballot for the Phase 2 revised definition of the
Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
1. Additional ballot
Anticipated Delivery
October 2013
2. Recirculation ballot
4Q13
3. BOT adoption
4Q13
Draft 3 – September 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 3 – September 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•
•
•
•
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells.
(to be removed from final draft – will be moved to the Reference Document)
•
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
•
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
Draft 3 – September 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
•
•
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
Draft 3 – September 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft 3 – September 2013
Page 5 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
Proposed Action Plan and Description of Current Draft:
This draft is the secondthird comment posting and successive ballot for the Phase 2 revised definition
of the Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
1. Additional ballot
Anticipated Delivery
October 2013
1.2.Recirculation ballot
34Q13
2.3.BOT adoption
4Q13
Draft 23 – AugustSeptember 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft 23 – AugustSeptember 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•
•
•
•
•
•
•
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
consisting of:
Individual resources that aggregate to a total capacity greater than 75 MVA (gross nameplate
rating), and
The system designed primarily for delivering capacity from the point where those resources
aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kV or
above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells.
(to be removed from final draft – will be moved to the Reference Document)
Draft 23 – AugustSeptember 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
•
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
•
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
Draft 23 – AugustSeptember 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
•
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft 23 – AugustSeptember 2013
Page 5 of 5
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
None.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after the date that
the definition 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 definition
shall become effective on the first day of the first calendar quarter after the date the definition is
adopted by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Compliance obligations for the Phase 2 definition would begin:
• Twenty-four months after the applicable effective date of the definition (for newly identified
Elements), or
• If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case-by-case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implementedNone.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after the date that
the definition 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 effectregulatory approval. Where approval by an applicable governmental authority is notIn those
jurisdictions where no regulatory approval is required, the definition shall go become effective on the
first day of the second calendar quarter after the date the definition is adopted by the NERC Board of
Trustees adoption or as otherwise made effective pursuant to the laws of applicable governmental
authoritiesprovided for in that jurisdiction.
Compliance obligations for the Phase 2 definition would begin:
• Twenty-four months after the applicable effective date of the definition (for newly identified
Elements), or
• If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case-by-case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
Unofficial Comment Form
Project 2010-17 Definition of Bulk Electric System – Phase 2
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the definition. The electronic comment form must be completed by 8:00 p.m. ET, October
28, 2013.
All documents and information about this project are available on the project page. If you have questions
please contact Ed Dobrowolski or by telephone at 609‐947‐3673.
Background Information - Project 2010-17 Definition of the BES (Phase 2)
The SDT has been working on addressing the issues and directives for Project 2010‐17 Definition of the
BES – Phase 2. The latest output of this work is shown in the third posting of the definition (the Phase 2
roadmap document). In this third posting, the SDT is responding to industry comments raised in the
second posting and successive ballot period that ended on September 4, 2013. The SDT has made the
following changes to the definition:
Inclusion I4: The language has been clarified based on industry comments to more clearly reflect the
SDT’s intent to include individual dispersed power producing units (such as wind and solar units) that
aggregate to greater than 75 MVA , along with the collector system that connects these units, from
the point they aggregate to greater than 75 MVA to the point of connection at 100kV or higher.
While the SDT recognizes that some stakeholders do not agree with the inclusion of individual
dispersed power producing units, FERC Orders 773 and 773‐A approved the inclusion of these
individual units. No stakeholder has provided a technical rationale to support removal of the
individual units from the definition. The SDT believes that stakeholder concerns about inclusion of
individual units may be addressed by specifying the Facilities to which an individual standard applies
within the Applicability section of that standard.
I4 ‐ Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA
(gross nameplate rating), and that are connected through a system designed primarily for delivering
such capacity to a common point of connection at a voltage of 100 kV or above. Thus, the facilities
designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a voltage
of 100 kV or above.
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
Questions
1. The SDT has re‐structured the language of Inclusion I4 to more clearly reflect the SDT’s intent to
include individual dispersed power producing units (such as wind and solar units) that aggregate to
greater than 75 MVA , along with the collector system that connects these units, from the point they
aggregate to greater than 75 MVA to the point of connection at 100kV or higher. While the SDT
recognizes that some stakeholders do not agree with the inclusion of individual dispersed power
producing units, FERC Orders 773 and 773‐A approved the inclusion of these individual units. No
stakeholder has provided a technical rationale to support removal of the individual units from the
definition. The SDT believes that stakeholder concerns about inclusion of individual units may be
addressed by specifying the Facilities to which an individual standard applies within the Applicability
section of that standard.
With this background, can you support the proposed clarifications to I4? If not, please provide
technical rationale for your disagreement along with suggested language changes.
Yes:
No:
Comments:
2. Are there any other concerns with this definition that haven’t been covered in previous postings,
questions and comments?
Yes:
No:
Comments:
Unofficial Comment Form
Project 2010‐17 DBES – Phase 2 (Third Draft) | September 2013
2
PUBLIC VERSION
White Paper on Bulk Electric System
Radial Exclusion (E1) Low Voltage
Loop Threshold
September 2013
Project 2010‐17: Definition of Bulk Electric System
Table of Contents
Background ..................................................................................................................................... 1
Executive Summary ........................................................................................................................ 2
Step 1: Establishment of Minimum Monitored Regional Voltage Levels ................................... 3
Step 1 Conclusion .................................................................................................................... 6
Step 2: Load Flows and Technical Considerations ....................................................................... 7
Step 2 Conclusion .................................................................................................................. 16
Study Conclusion .......................................................................................................................... 17
Appendix 1: Regional Elements ................................................................................................... 18
Appendix 2: One‐Line Diagrams…………………………………………………………………………………………….. 19
Appendix 3: Simulation Results ................................................................................................... 21
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV .......................................... 32
Bulk Electric System Radial Exclusion (E1)
Low Voltage Loop Threshold
Background
The definition of “Bulk Electric System” (BES) in the NERC Glossary consists of a core definition and a list
of facilities configurations that will be included or excluded from the core definition. The core definition
is used to establish the bright line of 100 kV, the overall demarcation point between BES and non‐BES
elements. Exclusion E1 applies to radial systems. In Order No. 773 and 773‐A, the Federal Energy
Regulatory Commission’s (Commission or FERC) expressed concerns that facilities operating below 100
kV may be required to support the reliable operation of the interconnected transmission system. The
Commission also indicated that additional factors beyond impedance must be considered to
demonstrate that looped or networked connections operating below 100 kV need not be considered in
the application of Exclusion E1.1
This document responds to the Commission’s concerns and provides a technical justification for the
establishment of a voltage threshold below which sub‐100 kV equipment need not be considered in the
evaluation of Exclusion E1.
NOTE: This justification does not address whether sub‐ 100 kV systems should be evaluated as
Bulk Electrical System (BES) Facilities. Sub‐ 100 kV systems are already excluded from the BES
under the core definition. Order 773, paragraph 155 states: “Thus, the Commission, while
disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements
in figure 3 in the bulk electric system, unless determined otherwise in the exception process.”
This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the
Final Rule, the sub‐100 kV elements comprising radial systems and local networks will not be
included in the bulk electric system, unless determined otherwise in the exception process.” Sub‐
100 kV facilities will only be included as BES Facilities if justified under the NERC Rules of
Procedure (ROP) Appendix 5C Exception Process.
1
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure, Order No.
773, 141 FERC ¶ 61,236 at P155, n.139 (2012); order on reh’g, Order No. 773‐A, 143 FERC ¶ 61,053 (2013).
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 1
Executive Summary
The Project 2010‐17 Standard Drafting Team conducted a two‐step process to establish a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops do not affect the
application of Exclusion E1. The justification for establishing a lower voltage threshold for application of
Exclusion E1 consisted of a two‐step technical approach:
Step 1: A review was performed to determine the minimum voltage levels that are monitored
by Balancing Authorities, Reliability Coordinators, and Transmission Operators for Interfaces,
Paths, and Monitored Elements. This minimum voltage level reflects a value that industry
experts consider necessary to monitor and facilitate the operation of the Bulk Electric System
(BES). This step provided a technically sound approach to screen for a minimum voltage limit
that served as a starting point for the technical analysis performed in Step 2 of this study.
Step 2: Technical studies modeling the physics of loop flows through sub‐100 kV systems were
performed to establish which voltage level, while less than 100 kV, should be considered in the
evaluation of Exclusion E1.
The analysis establishes that a 50 kV threshold for sub‐100 kV loops does not affect the application of
Exclusion E1. This approach will ease the administrative burden on entities as it negates the necessity
for an entity to prove that they qualify for Exclusion E1 if the sub‐100 kV loop in question is less than or
equal to 50 kV. This analysis provides an equally effective and efficient alternative to address the
Commission’s directives expressed in Order No. 773 and 773‐A.
It should be noted that, although this study resulted in a technically justified 50 kV threshold based on
proven analytic methods, there are other preventative loop flow methods that entities can apply on
sub‐100 kV loop systems to address physical equipment concerns. These methods include:
Interlocked control schemes;
Reverse power schemes;
Transformer, feeder and bus tie protection; and
Custom protection and control schemes.
These methods are discussed in detail in Appendix 4. The presence of such equipment does not alter the
criteria developed in this white paper, nor does it influence the conclusions reached. Additionally, the
presence of this equipment does not remove or lessen an entity’s obligations associated with the bright‐
line application of the Bulk Electric System (BES) definition.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 2
Radial Systems Exclusion (E1)
The proposed definition (first posting) of radial systems in the Phase 2 BES Definition (Exclusion E1) was:
A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV
or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2 and I3, with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in
Inclusions I2 and I3, with an aggregate capacity of non‐retail generation less than or equal
to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on prints or
one‐line diagrams for example, does not affect this exclusion.
Note 2 ‐ The presence of a contiguous loop, operated at a voltage level of 30 kV or less2, between
configurations being considered as radial systems, does not affect this exclusion.
STEP 1 – Establishment of Minimum Monitored Regional Voltage Levels
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The groupings of these elements have different names: for instance,
Paths in the Western Interconnection; Interfaces or Flowgates in the Eastern Interconnection; or
Monitored Elements in the Electric Reliability Council of Texas (ERCOT). Nevertheless, they all constitute
element groupings that operating entities (Reliability Coordinators, Balancing Authorities, and
Transmission Operators) monitor because they understand that they are necessary to ensure the
reliable operation of the interconnected transmission system under diverse operating conditions.
To provide information in determining a voltage level where the presence of a contiguous loop between
system configurations may not affect the determination of radial systems under Exclusion E1 of the BES
definition, voltage levels that are monitored on major Interfaces, Flowgates, Paths, and ERCOT
Monitored Elements were examined. This examination focused on elements owned and operated by
entities in North America. The objective was to identify the lowest monitored voltage level on these key
element groupings. The lowest monitored line voltage on the major element groupings provides an
indication of the lower limit which operating entities have historically believed necessary to ensure the
2
The first posting of this Phase 2 definition used a threshold of 30 kV; however as a result of the study work described in
this paper, the Standard Drafting Team has revised the threshold to 50 kV for subsequent industry consideration.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 3
reliable operation of the interconnected transmission system. The results of this analysis provided a
starting point for the technical analysis which was performed in Step 2 of this study.
Step 1 Approach
Each Region was requested to provide the key groupings of elements they monitor to ensure reliable
operation of the interconnected transmission system. This list, contained in Appendix 1, was reviewed
to identify the lowest voltage element in the major element groupings monitored by operating entities
in the eight Regions. Identification of this lowest voltage level served as a starting point to begin a
closer examination into the voltage level where the presence of a contiguous loop should not affect the
evaluation of radial systems under Exclusion E1 of the BES definition.
Step 1 Results
An examination of the line listings of the North American operating entities revealed that the majority of
operating entities do not monitor elements below 69 kV as shown in Table 1. However, in some
instances elements with line voltages of 34.5 kV were included in monitored element groupings. In no
instance was a transmission line element below 34.5 kV included in the monitored element groupings.
Region
Key Monitored Element Grouping
Lowest Line Element Voltage
FRCC
Southern Interface
115
MRO
NDEX
69
Total East PJM (Rockland Electric) – Hudson Valley
NPCC
34.5
(Zone G)1
RFC
MWEX
69
SERC
VACAR IDC2
100
SPP RE
SPSNORTH_STH
115
TRE
Valley Import GTL
138
WECC
Path 52 Silver Peak – Control 55 kV
55
Notes:
1. Two interfaces in NPCC/NYISO have lines with 34.5 kV elements.
2. The TVA area in SERC was not included in the tables attached to this report; however, a review of the
Flowgates in TVA revealed monitored elements no lower than 115 kV. There were a number of
Flowgates with 115 kV monitored elements in SERC, the monitored grouping listed is representative.
Table 1: Lowest Line Element Voltage Monitored by Region
In a few rare occasions there were transformer elements with low‐side windings lower than 30 kV included in
the key monitored element groupings as shown in Table 2.
Region
Interface
Element
Voltage (kV)
NPCC/NYISO
WEST CENTRAL: Genesee (Zone
B) – Central (Zone C)
New England ‐ Southwest
Connecticut
NPCC/ISO‐NE
(Farmtn 34.5/115kV&12/115 kV) #4
34.5/115 & 12/115
SOTHNGTN 5X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐5X)
SOTHNGTN 6X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐6X)
SOTHNGTN 11X ‐ Southington 115 kV
/27.6 kV Transformer (4C‐11X)
12/115
115/13.8
115/13.8
115/27.6
Table 2: Lowest Line Transformer Element Voltages Monitored by Region
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 4
Upon closer investigation, for New England’s Southwest Connecticut interface, it was determined that
the inclusion of these elements was the result of longstanding, historical interface definitions and not
for the purpose of addressing BES reliability concerns. Transformers serving lower voltage networks
continue to be included based on familiarity with the existing interface rather than a specific technical
concern. These transformers could be removed from the interface definition with no impact on
monitoring the reliability of the interconnected transmission system. For the New York West Central
interface, the low voltage element was included because the interface definition included boundary
transmission lines between Transmission Owner control areas; hence, it was included for completeness
to measure the power flow from one Transmission Owner control area to the other Transmission Owner
control area.
Further examination of the information provided by the eight NERC regions revealed that half of the
Regions only monitor transmission line elements with voltages above the 100 kV level. The other four
Regions, NPCC, RFC, MRO, and WECC, monitor transmission line elements below 100 kV as part of key
element groupings. However, in each of these cases, the number of below 100 kV transmission line
elements comprised less than 2.5% of the total monitored key element groupings. Figures 1 and 2
below depict the results of Step 1 of this study.
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 1: Voltage as Percent of Monitored Elements
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 5
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 2: Voltage as Percent of Monitored Elements per Region
Step 1 Conclusion
The results of Step 1 of this study regarding regional monitoring levels resulted in a determination that
30 kV was a reasonable voltage level to initiate the sensitivity analysis conducted in Step 2 of this study.
This value is below any of the regional monitoring levels. As noted herein, an examination of the line
listings of the North American operating entities revealed that the majority of operating entities do not
monitor elements below 69 kV as shown in Table 1. However, in some instances elements with line
voltages of 34.5 kV were included in monitored element groupings. In no instance was a transmission
line element below 34.5 kV included in the monitored element groupings.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 6
STEP 2 ‐ Load Flows and Technical Considerations
The threshold of 30 kV was established in Step 1 as a reasonable starting point to initiate the technical
sensitivity analysis performed in Step 2 of this study. The purpose of this step was to determine if there
is a technical justification to support a voltage threshold for the purpose of determining whether
facilities greater than 100 kV can be considered to be radial under the BES Definition Exclusion E1. If the
resulting voltage threshold was deemed appropriate through technical study efforts, then contiguous
loop connections operated at voltages below this value would not preclude the application of Exclusion
E1. Conversely, contiguous loops connecting radial lines at voltages above this kV value would negate
the ability for an entity to use Exclusion E1 for the subject facilities.
This study focused on two typical configurations: a distribution loop and a sub‐transmission loop. The
study evaluated a range of voltages for the loop and the parallel transmission system with the goal of
determining the voltage level below which single contingencies on the transmission system would not
result in power flow from a low voltage distribution or sub‐transmission loop to the BES. The study
included sensitivity analysis varying the loads and impedances. Variations in loop and transmission
system impedances account for a range of physical parameters such as conductor length, conductor
type, system configuration, and proximity of the loop to the transmission system. This study provided
the low voltage floor that can be used as a consideration for BES exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 7
Analytical Approach – Distribution Circuit Loop Example
The Project 2010‐17 Standard Drafting Team sought to examine the interaction and relative magnitude
of flows on the 100 kV and above Facilities of the electric system and those of any underlying low
voltage distribution loops. While not the determining factor leading to this study’s recommendation,
line outage distribution factors (LODF) were a useful tool in understanding the relationship between
underlying systems and the BES elements. It illustrated the relative scale of interaction between the BES
and the lower voltage systems and its review was a consideration when this study was performed. As
an example, the Standard Drafting Team considered a system similar to the one depicted in Figure 3
below. In this simplified depiction of a portion of an electric system, two radial 115 kV lines emanate
from 115 kV substations A and B to serve distribution loads via 115 kV distribution transformers at
stations C and D. Stations C and D are “looped” together via either a distribution bus tie (zero
impedance) or a feeder tie (modeled with typical distribution feeder impedances).
Figure 3: Example Radial Systems with Low Voltage Distribution Loop
With the example system, the Standard Drafting Team conducted power flow simulations to assess the
performance of the power system under single contingency outages of the line between stations A and
B. The analyses determined the LODF which represent the portion of the high voltage transmission flow
that would flow across the low voltage distribution circuit or bus ties under a single contingency outage
of the line between stations A and B. To the extent that the LODF values were negligible, this indicated a
minor or insignificant contribution of the distribution loops to the operation of the high voltage system.
But, more importantly, the analyses determined whether any instances of power flow reversal, i.e.,
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 8
resultant flow delivered into the BES, would occur during contingent operating scenarios. Instances of
flow reversal into the BES would indicate that the underlying distribution looped system is exhibiting
behavior similar to a sub‐transmission or transmission system, which would call into question the
applicability of radial exclusion E1.
The study work in this approach examined the sensitivity of parallel circuit flow on the distribution
elements to the size of the distribution transformers, the operating voltage of distribution delivery buses
at stations C and D and the strength of the transmission network serving stations A and B as manifested
in the variation of the transmission network transfer impedances used in the model.
In order to simply, yet accurately, represent this low voltage loop scenario between two radial circuits, a
Power System Simulator for Engineering (PSSE) model was created. Elements represented in this model
included the following:
Radial 115 kV lines from station A to station C and station B to station D;
Interconnecting transmission line from station A to station B;
Distribution transformers tapped off the 115 kV lines between stations A and C and between
stations B and D and at stations C and D;
Feeder tie impedance to represent a feeder tie (or zero impedance bus tie) between distribution
buses at stations C and D;
Transfer impedance equivalent between stations A and B, representing the strength of the
interconnected transmission network3.
Within this model, parameters were modified to simulate differences in the length and impedance of
the transmission lines, the amount of distribution load, the strength of the transmission network
supplying stations A and B, the size of the distribution transformers and the character of the bus or
feeder ties at distribution Stations C and D.
Distribution Model Simulation
Table 3 below illustrates the domain of the various parameters that were simulated in this distribution
circuit loop scenario. A parametric analysis was performed using all combinations of variables shown in
each column of the upper portion of Table 3. Sensitivity analysis was performed as indicated in the
lower portion of the table.
3
The relative strength of the surrounding transmission system network is a function of the quantity of parallel
transmission paths and the impedance of those paths between the two source substations. A high number of parallel
paths with low impedance translates to a low transfer impedance, which allows power to more readily flow between the
stations. Conversely, a low number of parallel paths having higher impedance is represented by a relatively large
transfer impedance.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 9
Trans KV
Trans Length
115
10 miles
Sensitivity Analysis:
Dist KV
Dist Length
XFMR MVA
12.5
23
34.5
46
0 (bus tie)
2 miles
5 miles
10
20
40
Dist Load % Z Transfer
rating
40
Weak
80
Strong
Medium
Notes:
1. The “medium” value for transfer impedances was derived from an actual example system in the
northeastern US. This was deemed to be representative of a network with typical, or medium,
transmission strength. Variations of a stronger (more tightly coupled) and a weaker transmission network
were selected for the “strong” and “weak” cases, respectively. Impedance values of X=0.54%, X=1.95%,
and X=4.07% were applied for the strong, medium and weak cases, respectively.
Table 3: Model Parameters Varied
The model was used to examine a series of cases simulating a power transfer on the 115 kV line4 from
station A to station B of slightly more than 100 MW. Loads and impedances were simulated at the
location shown in Figure 5 of Appendix 2. Two load levels were used in each scenario: 40% of the rating
of the distribution transformer and 80% of the rating. Distribution transformer ratings were varied in
three steps: 10 MVA, 20 MVA, and 40 MVA. Finally, the strength of the interconnected transmission
network was varied in three steps representing a strong, medium, and weak transmission network. The
choices of transfer impedance were based on typical networks in use across North America. A specific
model from the New England area of the United States yielded an actual transfer impedance of 0.319 +
j1.954%. This represents the ’medium’ strength transmission system used in the analyses. The other
values used in the study are minimum (’strong’) and maximum (’weak’) ends of the typical range of
transfer impedances for 115 kV systems interconnected to the Bulk Electric System of North America.
Distribution feeder connections were simulated in three different ways, first with zero impedance
between the distribution buses at stations C and D, second with a 2‐mile feeder connection with typical
overhead conductor, and third with a 5‐mile connection.
Distribution Model Results
23 kV Distribution System
The results show LODFs ranging from a low of 0.2% to a high of 6.7%. In all of the cases, the direction of
power flow to the radial lines at stations A and B was toward stations C and D. In other words, there
were no instances of flow reversal from the distribution system back to the 115 kV transmission system.
The lowest LODF was found in the case with the smallest distribution transformers (10 MVA), the 5‐mile
distribution circuit tie, and the strong transmission transfer impedance. The case with the highest LODF
4
The threshold voltage of 115 kV provides conservative results. At a higher voltage, such as 230 kV, the reflection of
distribution impedance to the transmission system is significantly larger, and hence, the amount of distribution power
flow will be much smaller.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 10
was that which used the largest distribution transformers (40 MVA) with the lightest load and the use of
a zero‐impedance bus tie between the two distribution stations.
12.5 kV Distribution System
As compared to the simulations using the 23 kV distribution system, the 12.5 kV system model yielded
far lower LODF values. This result is reasonable, as the reflection of impedances on a 12.5 kV
distribution system will be nearly four times as large as those for a 23 kV distribution system, and the
transformer sizes in use at the 12.5 kV class are generally smaller, i.e., higher impedance. As with the
cases simulated for the 23 kV system, the 12.5 kV system exhibited a power flow direction in the radial
line terminals at stations A and B in the direction of the distribution stations C and D; no flow reversal
was seen in any of the contingency cases.
Given the lower voltage of the distribution system, the cases studied at this low voltage level were
limited to the scenario with the high transfer impedance value (’weak’ transmission case). This is a
conservative assumption as all cases with lower transfer impedance will yield far lower LODF values.
With that, the range of LODF values was found to be 1.0% to 6.7%. When compared with the 23 kV
system results in the weak transmission case, the range of LODF values was 1.8% to 6.7%. Higher LODF
values were found in the cases with the largest transformer size, which is to be expected.
Table 4 below provides a sample of the results of the various simulations that were conducted. The full
collection of results is provided in Appendix 3.
Case
D, KV
623a5
623a5pk
633b0pk
723c0
723c5pk
823b0
823c0
812a5
812b0
812b5pk
812c0
834a5pk
834b5pk
834d0
834d0pk
846e0
846e2
846e5
23
23
23
23
23
23
23
12.5
12.5
12.5
12.5
34.5
34.5
34.5
34.5
46
46
46
Z xfer
strong
strong
strong
medium
medium
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
ZDist
5 mi
5 mi
0
0
5 mi
0
0
5 mi
0
5 mi
0
5 mi
5 mi
0
0
0
2 mi
5 mi
XFMR MVA
Load, MW
LODF
10
10
20
40
40
20
40
10
20
20
40
10
20
40
40
50
50
50
4
8
16
16
32
8
16
4
8
16
16
8
16
16
32
16
20
20
0.2%
0.3%
0.4%
3.4%
1.6%
3.8%
6.7%
1.0%
3.8%
1.3%
6.7%
1.7%
3.0%
8.9%
8.7%
10.3%
9.0%
7.4%
Table 4: Select Sample of Study Results for Distribution Scenario
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 11
34.5 kV and 46 kV Distribution Systems
As with the analysis done for the 12.5 kV system, a conservative transfer impedance value, that of the
’weak’ transmission network, was used in selecting the transfer impedance to be used in the simulations
at 34.5 kV and 46 kV. With this conservative parameter, the simulation results show distribution factors
(LODF) ranging from a low of 1.7% to a high of 10.3%. In all of the cases, the direction of power flow to
the radial lines remained from stations A and B toward stations C and D. In other words, there were no
instances of flow reversal from the distribution system back to the 115 kV transmission system.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 12
Analytical Approach – Sub‐transmission Example
In addition to the distribution circuit loop example described above, the study examined the
performance of systems typically described as ’sub‐transmission.’ The study sought to examine the
interaction and relative magnitude of flows on the 100 kV and above Facilities of the interconnected
transmission system and those of the underlying parallel sub‐transmission facilities. The study
considered a system similar to the one depicted in Figure 4 below. In this simplified depiction of a
portion of a transmission and sub‐transmission system, a 40‐mile transmission line connecting two
sources with transfer impedance between the two sources representing the parallel transmission
network. Each source also supplies a 10‐mile transmission line with a load tap at the mid‐point of the
line, each serving a load of 16 MW. At the end of each of these lines is a step‐down transformer to the
sub‐transmission voltage, where an additional load is served. The two sub‐transmission stations are
connected by a 25‐mile sub‐transmission tie line. Loads and impedances were simulated at the location
shown in Figure 6 of Appendix 2.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 13
Figure 4: Example Radial Systems with Sub‐transmission Loop
Given this example sub‐transmission system, a PSSE model was created to simulate the power flow
characteristics of the system during a contingency outage of the transmission line between stations A
and B. Within this model, parameters were modified to simulate differences in the amount of load
being served, transformer size and the amount of pre‐contingent power flow on the transmission line.
All simulations were performed with a transfer impedance representative of a ‘weak’ transmission
network, which was confirmed as conservative in the distribution system analysis.
Sub‐transmission Model Simulation
Simulations were performed for each sub‐transmission voltage (34.5 kV, 46 kV, 55 kV, and 69 kV) using a
transmission voltage of 115 kV. This analysis identified the potential for power flowing back to the
transmission system only for sub‐transmission voltages of 55 kV and 69 kV. Sensitivity analysis was
performed using higher transmission voltages to confirm that cases modeling a 115 kV transmission
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 14
system yield the most conservative results. Therefore, it was not necessary to perform sensitivity
analysis for sub‐transmission voltages of 34.5 kV and 46 kV for transmission voltages higher than 115 kV.
Table 5 below illustrates the domain of the various parameters that were simulated in this sub‐
transmission circuit loop scenario. A parametric analysis was performed using combinations of variables
shown in each column of Table 5.
Trans KV
Trans Length Sub‐T KV
Sub‐T Length XFMR MVA
Dist Load
Trans MW
% rating
Preload
115
40 miles
34.5
25 miles
40
40
115
46
50
55
60
69
Sensitivity Analyses:
138
40 miles
55
25 miles
50
40
115
161
69
60
135
230
150
220
Table 5: Model Parameters and Sensitivities
Sub‐transmission Model Results
115 kV Transmission System with 34.5‐69 kV Sub‐transmission
The results for cases depicting a 115 kV transmission system voltage and ranges of 34.5 kV to 69 kV sub‐
transmission voltages show line outage distribution factors (LODF) in the range of 9% to slightly higher
than 20%. Several cases show a reversal of power flow in the post‐contingent system such that power
flow is delivered from the sub‐transmission system into the 115 kV BES. The worst case is found in the
69 kV sub‐transmission voltage class. This result is as expected, given that the impedance of the 69 kV
sub‐transmission system is less than the impedances of lower voltage systems. In no instance was a
reversal of power flow observed in sub‐transmission systems rated below 50 kV.
138 kV and 161 kV Transmission Systems with 55‐69 kV Sub‐transmission
The results for cases of 138 kV and 161 kV transmission system voltages supplying sub‐transmission
voltages of 55 kV and 69 kV show LODFs ranging from 9% to 16%. These cases also result in reversal of
power flows in the post‐contingent system such that power flow is delivered from the sub‐transmission
system into the 115 kV BES.
230 kV Transmission System with 55‐69 kV Sub‐transmission
By simulating a higher BES source voltage of 230 kV paired with sub‐transmission voltages of 55 kV and
69 kV, the transformation ratio is sufficiently large to result in a significant increase to the reflected sub‐
transmission system impedance. Therefore, in these cases, LODFs range from 5% to 7%, and these cases
also show no reversal of power flow toward the BES in the post‐contingent system. Table 6 below
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 15
provides a sample of the results of the various simulations that were conducted. All results are provided
in Appendix 3.
Case
T, KV
S‐T, KV
834d25
846e25
855e25
869f25
855e25‐138
855e25‐138’
869f25‐138
869f25‐138’
855e25‐161
855e25‐161’
869f25‐161
869f25‐161’
855e25‐230
855e25‐230’
869f25‐230
869f25‐230’
115
115
115
115
138
138
138
138
161
161
161
161
230
230
230
230
34.5
46
55
69
55
55
69
69
55
55
69
69
55
55
69
69
Trans Pre‐
load, MW
115
114
112
110
114
134
112
132
114
155
113
153
116
219
116
218
XFMR MVA
Load, MW
LODF
40
50
50
60
50
60
60
60
50
60
60
60
50
60
60
60
20
20
20
24
20
20
24
24
20
20
24
24
20
20
24
24
9.4%
13.3%
15.7%
20.3%
11.7%
11.9%
15.6%
15.8%
9.1%
9.2%
12.5%
12.6%
4.9%
5.0%
7.0%
7.0%
Flow Rev
to BES?
Yes
Yes
Yes
Yes
Yes
Yes
Table 6: Select Sample of Study Results for Sub‐transmission Scenario
Step 2 Conclusion
After conducting extensive simulations (included in Appendix 3), the results of Step 2 of this analysis
indicates that 50 kV is the appropriate low voltage loop threshold below which sub‐100 kV loops should
not affect the application of Exclusion E1 of the BES Definition. Simulations of power flows for the cases
modeled in this study show there is no power flow reversal into the BES when circuit loop operating
voltages are below 50 kV. This study also finds, for loop voltages above 50 kV, certain cases result in
power flow toward the BES. Therefore, the study concludes that low voltage circuit loops operated
below 50 kV should not affect the application of Exclusion E1.
As described throughout the preceding section, the scenarios and configurations utilized in this analysis
represent the majority of cases that will be encountered in the industry. The models used in this
analysis establish reasonable bounds and use conservative parameters in the scenarios. However, there
may be actual cases that deviate from these modeled scenarios, and therefore, results could be
somewhat different than the ranges of results from this analysis. Such deviations are expected to be
rare and can be processed through the companion BES Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 16
Study Conclusion
The Project 2010‐17 Standard Drafting Team conducted a two‐step study process to yield a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops should not affect
the application of Exclusion E1.
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The objective of Step 1 was to identify the lowest monitored voltage
level on these key element groupings. The lowest monitored line voltage on the major element
groupings provides an indication of the lower limit which operating entities have historically believed
necessary to ensure the reliable operation of the interconnected transmission system.
As a result of studying such regional monitoring levels, Step 1 concluded that 30 kV was a reasonable
voltage level to initiate the sensitivity analysis conducted in Step 2. This is a conservative value as it is
below any of the regional monitoring levels.
Using the conservative value established by Step 1, the Standard Drafting Team conducted extensive
simulations of power flows which demonstrated that there is no power flow reversal into the BES when
circuit loop operating voltages are below 50 kV. Therefore, the study concludes that low voltage circuit
loops operated below 50 kV should not affect the application of Exclusion E1. This analysis provides an
equally effective and efficient alternative to address the Commission’s directives expressed in Order No.
773 and 773‐A.
The scenarios and configurations utilized in this analysis represent the majority of cases that will be
encountered in the industry. The models used in this analysis establish reasonable bounds and use
conservative parameters in the scenarios. However, there may be actual cases that deviate from these
modeled scenarios, and therefore, results could be somewhat different than the ranges of results from
this analysis. Such deviations are expected to be rare and can be processed through the companion BES
Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 17
Appendix 1: Regional Elements
PRIVILEGED AND CONFIDENTIAL INFORMATION HAS BEEN REDACTED FROM THIS PUBLIC VERSION
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 18
Appendix 2: One‐Line Diagrams
Note: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Figure 5: Example Radial Systems with Low Voltage Distribution Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 19
Notes: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Step‐down transformers from sub‐transmission voltage to distribution voltage were not explicitly
modeled in the simulations.
Figure 6: Example Radial Systems with Sub‐transmission Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 20
Appendix 3: Simulation Results
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
23 kV Base Cases
623a0
10
Strong
15
0
10%/10
10%/10
4.0
4.0
110.7
10.9
6.9
1.1
5.1
11.2
7.2
0.8
4.8
0.003
623a2
10
Strong
15
2
10%/10
10%/10
4.0
4.0
110.7
10.7
6.7
1.4
5.4
10.9
6.9
1.1
5.1
0.002
623a5
10
Strong
15
5
10%/10
10%/10
4.0
4.0
110.7
10.3
6.3
1.7
5.7
10.5
6.5
1.5
5.5
0.002
623a0pk
10
Strong
15
0
10%/10
10%/10
8.0
8.0
111.4
19.0
10.9
5.1
13.1
19.3
11.2
4.8
12.8
0.003
623a2pk
10
Strong
15
2
10%/10
10%/10
8.0
8.0
111.4
18.7
10.7
5.4
13.4
18.9
10.9
5.1
13.1
0.002
623a5pk
10
Strong
15
5
10%/10
10%/10
8.0
8.0
111.5
18.3
10.3
5.7
13.7
18.6
10.5
5.5
13.5
0.003
623b0
10
Strong
15
0
10%/20
10%/20
8.0
8.0
111.1
21.7
13.7
2.3
10.3
22.3
14.2
1.8
9.8
0.005
623b2
10
Strong
15
2
10%/20
10%/20
8.0
8.0
111.2
20.7
12.7
3.3
11.3
21.2
13.2
2.9
10.9
0.004
623b5
10
Strong
15
5
10%/20
10%/20
8.0
8.0
111.3
19.7
11.7
4.3
12.3
20.1
12.1
4.0
12.0
0.004
623b0pk
10
Strong
15
0
10%/20
10%/20
16.0
16.0
112.6
37.8
21.7
10.3
26.3
38.3
22.3
9.7
25.8
0.004
623b2pk
10
Strong
15
2
10%/20
10%/20
16.0
16.0
112.7
36.7
20.7
11.3
27.3
37.2
21.2
10.9
26.9
0.004
623b5pk
10
Strong
15
5
10%/20
10%/20
16.0
16.0
112.8
35.7
19.7
12.3
28.4
36.1
20.1
12.0
28.0
0.004
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 21
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
623c0
10
Strong
15
0
10%/40
10%/40
16.0
16.0
112.2
42.7
26.6
5.4
21.4
43.7
27.7
4.3
20.3
0.009
623c2
10
Strong
15
2
10%/40
10%/40
16.0
16.0
112.5
39.6
23.6
8.4
24.4
40.4
24.4
7.7
23.7
0.007
623c5
10
Strong
15
5
10%/40
10%/40
16.0
16.0
112.7
37.3
21.3
10.8
26.8
37.8
21.8
10.3
26.3
0.004
LODF
623c0pk
10
Strong
15
0
10%/40
10%/40
32.0
32.0
115.1
74.9
42.8
21.2
53.3
76.0
43.9
20.2
52.2
0.010
623c2pk
10
Strong
15
2
10%/40
10%/40
32.0
32.0
115.4
71.8
39.7
24.3
56.4
72.6
40.5
23.6
55.6
0.007
623c5pk
10
Strong
15
5
10%/40
10%/40
32.0
32.0
115.6
69.4
37.4
26.7
58.8
70.0
37.9
26.2
58.3
0.005
723a0
10
Medium
15
0
10%/10
10%/10
4.0
4.0
108.3
10.9
6.9
1.1
5.1
11.9
7.9
0.1
4.1
0.009
723a2
10
Medium
15
2
10%/10
10%/10
4.0
4.0
108.3
10.6
6.6
1.4
5.4
11.5
7.5
0.5
4.5
0.008
723a5
10
Medium
15
5
10%/10
10%/10
4.0
4.0
108.4
10.3
6.3
1.8
5.8
11.1
7.1
1.0
5.0
0.007
723a0pk
10
Medium
15
0
10%/10
10%/10
8.0
8.0
110.4
18.9
10.9
5.1
13.1
20.0
12.0
4.0
12.1
0.010
723a2pk
10
Medium
15
2
10%/10
10%/10
8.0
8.0
110.5
18.6
10.6
5.4
13.4
19.6
11.6
4.4
12.5
0.009
723a5pk
10
Medium
15
5
10%/10
10%/10
8.0
8.0
110.6
18.3
10.3
5.7
13.7
19.1
11.1
4.9
12.9
0.007
723b0
10
Medium
15
0
10%/20
10%/20
8.0
8.0
109.7
21.6
13.6
2.4
10.4
23.6
15.6
0.4
8.4
0.018
723b2
10
Medium
15
2
10%/20
10%/20
8.0
8.0
110.0
20.6
12.6
3.4
11.4
22.3
14.3
1.7
9.8
0.015
723b5
10
Medium
15
5
10%/20
10%/20
8.0
8.0
110.2
19.7
11.7
4.4
12.4
21.0
13.0
3.1
11.1
0.012
723b0pk
10
Medium
15
0
10%/20
10%/20
16.0
16.0
114.0
37.8
21.8
10.2
26.3
39.9
23.8
8.2
24.2
0.018
723b2pk
10
Medium
15
2
10%/20
10%/20
16.0
16.0
114.3
36.8
20.8
11.3
27.3
38.5
22.5
9.6
25.6
0.015
723b5pk
10
Medium
15
5
10%/20
10%/20
16.0
16.0
114.5
35.8
19.8
12.3
28.3
37.2
21.1
10.9
27.0
0.012
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 22
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
723c0
10
Medium
15
0
10%/40
10%/40
16.0
16.0
112.6
42.7
26.7
5.3
21.3
46.5
31.4
1.6
17.6
0.034
723c2
10
Medium
15
2
10%/40
10%/40
16.0
16.0
113.5
39.7
23.7
8.4
24.4
42.4
26.4
5.7
21.7
0.024
723c5
10
Medium
15
5
10%/40
10%/40
16.0
16.0
114.1
37.4
21.4
10.7
26.7
39.3
23.3
8.8
24.8
0.017
723c0pk
10
Medium
15
0
10%/40
10%/40
32.0
32.0
121.2
75.5
43.4
20.7
52.7
79.5
47.4
16.7
48.7
0.033
723c2pk
10
Medium
15
2
10%/40
10%/40
32.0
32.0
122.0
72.2
40.1
23.9
55.9
75.2
43.1
21.1
53.1
0.025
723c5pk
10
Medium
15
5
10%/40
10%/40
32.0
32.0
122.7
69.8
37.7
26.4
58.5
71.8
39.7
24.4
56.5
0.016
823a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
823a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
823a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.4
10.2
62.0
1.8
5.8
11.9
7.9
0.2
4.2
0.016
823a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
823a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.6
12.6
3.5
11.5
0.018
823a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.8
18.3
10.3
5.7
13.8
20.0
12.0
4.0
12.1
0.015
823b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
823b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.8
20.6
12.6
3.4
11.4
24.0
16.0
0.1
8.1
0.031
823b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
109.2
19.6
11.6
4.4
12.4
22.3
14.3
1.8
9.8
0.025
823b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
823b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.7
36.9
20.8
11.2
27.2
40.4
24.4
7.7
23.7
0.030
823b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
116.2
35.9
19.8
12.2
28.2
38.7
22.7
9.4
25.5
0.024
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 23
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
823c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
823c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
114.4
39.7
23.7
8.3
24.3
45.4
29.3
2.8
18.8
0.050
823c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
115.5
37.4
21.4
10.6
26.7
41.4
25.4
6.8
22.8
0.035
823c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
823c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
128.2
72.7
40.6
23.5
55.6
78.9
48.6
17.4
49.5
0.048
823c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
129.3
70.1
38.0
26.1
58.2
74.5
42.4
21.8
53.9
0.034
Sensitivity to Length of Lines 1‐4
723a0_30
10
Medium
30
0
10%/10
10%/10
4.0
4.0
108.3
10.8
6.8
1.2
5.2
11.8
7.8
0.2
4.2
0.009
723a2_30
10
Medium
30
2
10%/10
10%/10
4.0
4.0
108.4
10.5
6.5
1.5
5.5
11.4
7.4
0.6
4.6
0.008
723a5_30
10
Medium
30
5
10%/10
10%/10
4.0
4.0
108.5
10.2
6.2
1.8
5.8
11.0
7.0
1.0
5.0
0.007
Selected 34.5 kV cases
834a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
834a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.1
10.7
6.7
1.3
5.3
12.7
8.7
‐0.7
3.3
0.019
834a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
834a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
834a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.6
18.8
10.8
5.2
13.3
20.8
12.8
3.2
11.2
0.018
834a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.5
12.5
3.5
11.5
0.017
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
834b0
10
Weak
15
0
10%/20
10%/20
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 24
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
834b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.6
21.1
13.1
2.9
10.9
24.8
16.8
‐0.7
7.3
0.034
834b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
108.9
20.5
12.5
3.5
11.5
23.8
15.8
0.3
8.3
0.030
LODF
834b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
834b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.5
37.4
21.4
10.7
26.7
41.3
25.3
6.8
22.8
0.034
834b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
115.8
36.8
20.7
11.3
27.3
40.3
24.2
7.8
23.9
0.030
834c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
834c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
113.8
41.2
25.2
6.9
22.9
47.8
31.7
0.4
16.4
0.058
834c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
114.6
39.5
23.5
8.5
24.6
45.0
29.0
3.2
19.2
0.048
834c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
834c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
127.5
74.2
42.1
21.9
54.0
81.5
49.4
14.7
46.8
0.057
834c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
128.3
72.4
40.3
23.8
55.8
78.5
46.4
17.9
49.9
0.048
834d0
10
Weak
15
0
7%/40
7%/40
16.0
16.0
111.6
46.3
30.3
1.7
17.7
56.2
40.1
‐8.1
7.9
0.089
834d2
10
Weak
15
2
7%/40
7%/40
16.0
16.0
112.8
43.6
27.6
4.4
20.4
51.8
35.8
‐3.6
12.4
0.073
834d5
10
Weak
15
5
7%/40
7%/40
16.0
16.0
113.9
41.1
25.1
7.0
23.0
47.6
31.6
0.6
16.6
0.057
834d0pk
10
Weak
15
0
7%/40
7%/40
32.0
32.0
124.9
80.0
47.9
16.2
48.2
90.9
58.8
5.3
37.3
0.087
834d2pk
10
Weak
15
2
7%/40
7%/40
32.0
32.0
126.3
77.0
44.9
19.2
51.2
86.1
54.0
10.2
42.2
0.072
834d5pk
10
Weak
15
5
7%/40
7%/40
32.0
32.0
127.5
74.2
42.1
22.0
54.1
81.4
49.3
15.0
47.0
0.056
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 25
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
Selected 12.47 kV cases
812a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
812a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.4
10.1
6.1
1.9
5.9
11.6
7.6
0.4
4.4
0.014
812a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.7
9.4
5.4
2.6
6.6
10.5
6.5
1.5
5.5
0.010
812a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
812a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.9
18.1
10.1
5.9
13.9
19.7
11.7
4.3
12.4
0.015
812a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
110.2
17.5
9.5
6.5
14.5
18.6
10.6
5.5
13.5
0.010
812b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
812b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
109.4
19.2
11.2
4.8
12.8
21.7
13.6
2.5
10.5
0.023
812b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
110.0
17.9
9.9
6.1
14.1
19.4
11.4
4.7
12.7
0.014
812b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
812b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
116.4
35.4
19.4
12.6
28.6
38.0
22.0
10.2
26.2
0.022
812b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
117.0
34.1
18.0
14.0
30.0
35.6
19.6
12.6
28.6
0.013
812c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
812c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
115.9
36.6
20.6
11.5
27.5
40.0
24.0
8.3
24.3
0.029
812c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
116.8
34.4
18.4
13.7
29.7
36.2
20.2
12.0
28.0
0.015
812c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
812c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
129.7
69.2
37.1
27.1
59.1
73.0
40.9
23.5
55.5
0.029
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 26
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
10
Weak
15
5
10%/40
10%/40
32.0
32.0
130.8
66.7
34.7
29.4
61.5
68.8
36.7
27.6
59.6
0.016
846e0
10
Weak
15
0
10%/40
7%/50
16.0
20.0
112.1
53.1
37.1
2.9
18.9
64.7
48.7
‐8.6
7.4
0.103
846e2
10
Weak
15
2
10%/40
7%/50
16.0
20.0
113.2
50.7
34.7
5.3
21.3
60.9
44.8
‐4.7
11.3
0.090
846e5
10
Weak
15
5
10%/40
7%/50
16.0
20.0
114.3
48.2
32.1
7.9
24.0
56.7
40.7
‐0.4
15.6
0.074
669f25
40
Strong
20
25
10%/40
7%/60
16.0
24.0
114.0
76.0
59.8
‐10.8
5.2
79.6
63.4
‐14.2
1.8
0.032
769f25
40
Medium
20
25
10%/40
7%/60
16.0
24.0
111.7
75.3
59.1
‐10.1
5.9
87.3
71.0
‐21.2
‐5.2
0.107
869f25
40
Weak
20
25
10%/40
7%/60
16.0
24.0
109.8
74.7
58.5
‐9.6
6.4
97.0
80.6
‐30.0
‐14.0
0.203
812c5pk
LODF
Selected 46 kV cases
Sub‐transmission cases
115‐69 kV
115‐55 kV
655e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
114.5
62.1
46.0
‐5.0
11.0
64.8
48.7
‐7.5
8.5
0.024
755e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
113.3
61.8
45.7
‐4.8
11.2
70.9
54.8
‐13.0
3.0
0.080
855e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
112.1
61.5
45.4
‐4.5
11.5
79.1
62.9
‐20.2
‐4.2
0.157
855f25
115‐46 kV
646e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
115.0
57.3
41.2
‐0.2
15.8
59.5
43.4
‐2.1
13.9
0.019
746e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
114.6
57.2
41.2
‐0.1
15.9
64.9
48.8
‐6.8
9.2
0.067
846e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.2
57.2
41.1
0.0
16.0
72.4
56.2
‐13.1
2.9
0.133
40
Strong
20
25
10%/40
7%/40
16.0
16.0
115.3
46.2
30.2
2.6
18.7
47.7
31.7
1.4
17.4
0.013
115‐34.5 kV
634d25
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 27
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
734d25
40
Medium
20
25
10%/40
7%/40
16.0
16.0
115.4
46.3
30.2
2.6
18.6
51.5
35.5
‐1.9
14.1
0.045
834d25
40
Weak
20
25
10%/40
7%/40
16.0
16.0
115.5
46.3
30.2
2.6
18.6
57.1
41.0
‐6.4
9.6
0.094
869f25‐138
40
Weak
20
25
10%/40
7%/60
16.0
24.0
112.0
66.5
50.4
‐1.8
14.2
84.0
67.9
‐18.3
‐2.3
0.156
869f25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
131.9
71.1
55.0
‐6.3
9.8
92.0
75.8
‐25.6
‐9.6
0.158
LODF
138‐69 kV
138‐55 kV
855e25‐138
40
Weak
20
25
10%/40
7%/50
16.0
20.0
113.5
55.1
39.0
1.5
17.5
68.4
52.3
‐10.8
5.2
0.117
855e25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
134.0
58.5
42.4
‐1.7
14.3
74.4
58.3
‐16.2
‐0.2
0.119
869f25‐161
40
Weak
20
25
10%/40
7%/60
16.0
24.0
113.2
60.7
44.7
3.7
19.7
74.8
58.8
‐9.8
6.2
0.125
869f25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
153.0
68.0
52.0
‐3.3
12.7
87.3
71.2
‐21.4
‐5.4
0.126
855e25‐161
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.1
50.7
34.7
5.6
21.6
61.1
45.1
‐4.2
11.8
0.091
855e25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
154.8
56.0
40.0
0.6
16.6
70.3
54.3
‐12.6
3.4
0.092
869f25‐230
40
Weak
20
25
10%/40
7%/60
16.0
24.0
116.3
51.3
35.3
12.8
28.8
59.4
43.3
5.0
21.0
0.070
869f25‐230'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
217.7
61.2
45.2
3.2
19.2
76.5
60.4
‐11.4
4.7
0.070
855e25‐230
40
Weak
20
25
10%/40
7%/50
16.0
20.0
116.1
43.8
27.8
12.3
28.3
49.5
33.5
6.7
22.8
0.049
855e25‐230'
40
Weak
20
25
10%/40
7%/50
16.0
20.0
218.7
50.8
34.8
5.6
21.6
61.7
45.7
‐4.7
11.3
0.050
161‐69 kV
161‐55 kV
230‐69 kV
230‐55 kV
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 28
Notes:
The following notes provide information to understand the meaning of each column heading and
underlying assumptions used in the analysis. See also the one‐line diagrams in Figures 5 and 6 of
Appendix 2 for additional information.
ZL
The table provides the length of line “L” in miles to provide a high‐level, qualitative understanding of the
line impedance. The line impedance (ZL) is the length of the line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
230
954 ACSR
25.20’
0.100 + j0.786
0.000189 + J 0.00149
954 ACSR
20’ H‐frame
16’ H‐frame
161
20.16’
0.100 + j0.759
0.000384 + j 0.00293
138
795 ACSR
13’ H‐frame
16.38’
0.117 + j0.738
0.000615 + j 0.00388
115
795 ACSR
11’ H‐frame
13.86’
0.117 + j0.718
0.000886 + j 0.00543
Ztr
The transfer impedance (Ztr) represents the impedance of the system in parallel with the subsystem
under study. Analysis was performed for three levels of parallel transfer impedance which have been
characterized as strong, medium, and weak. The strong system has relatively low impedance and thus
will pick up more power flow when line “L” is tripped. The weak system has relatively high impedance
and thus will pick up less power flow when line “L” is tripped. The medium system has a mid‐range
impedance value. The actual values of the transfer impedance vary between the distribution cases and
the sub‐transmission cases.
Ztr in distribution cases (p.u.)
Ztr in sub‐transmission cases (p.u.)
Strong
0.00089 + j 0.00543
0.00354 + j 0.0217
Medium
0.00319 + j 0.0195
0.0128 + j 0.0782
Weak
0.00664 + j 0.0407
0.0266 + j 0.163
Zln1‐4
The table provides the total length of lines “ln1” through “ln4.” In all simulations these four lines have
equal length. The total length in miles provides a high‐level, qualitative understanding of the line
impedance. The line impedances are the length of each line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are the same as provided above for line “L.”
Zdist
The table provides the length of the line in miles to provide a high‐level, qualitative understanding of the
line impedance. The impedance of the distribution system or sub‐transmission system (Zdist) is the length
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 29
of the distribution tie or sub‐transmission line in miles times the per mile impedance. A value of zero
miles is used when the distribution tie is a solid bus tie. Assumptions used in determining the per mile
impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
69
636 ACSR
6’ Horizontal
7.56’
0.145 + j0.657
0.00305 + j 0.0138
55
556 ACSR
6’ Horizontal
7.56’
0.168 + j0.677
0.00555 + j 0.0224
46
477 ACSR
6’ Triangular
6.00’
0.193 + j0.647
0.00913 + j 0.0306
34.5
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0162 + j 0.0503
23
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0365 + j 0.113
12.47
336 ACSR
2’ Horizontal
2.52’
0.274 + j0.563
0.176 + j 0.362
ZT1‐4
The transformer impedance is reported as percent impedance on the transformer MVA base. Each
transformer has three ratings: OA (oil and air), FA (forced air – i.e., fans), and FOA (forced oil and air –
i.e., pumps and fans). The transformer MVA base rating is the OA rating. The FA rating is 133% of the OA
rating and the FOA rating is 167% of the OA rating (e.g., a 20 MVA transformer has a 20 MVA OA rating,
26.7 MVA FA rating, and 33.3 MVA FOA rating, typically identified as a nameplate of 20/26.7/33.3 MVA).
The transformer impedance and rating for each voltage level are based on typical values. Distribution
transformer impedance is generally higher to limit current on the distribution equipment. Secondary
current typically is not a concern on sub‐transmission transformers, so impedance is typically lower to
limit reactive power losses and voltage drop.
L1, L2, L3, L4
The transformer load is based on the transformer OA rating. Transformers are loaded at 80 percent of
the transformer base MVA in the simulations modeling a peak system load condition. The substations
modeled have two transformers, with each transformer able to supply the total station load. Thus, if one
transformer is forced out‐of‐service, the load on the remaining transformer will be 160 percent of its
base rating, which is approximately equal to its FOA rating.
Transformers are loaded at 40 percent of the transformer base MVA in the simulations modeling a light
system load condition.
HV Line "L" in‐service: PL, Pln1, , Pln2, Pln3, Pln4
The loading on each line, with all lines in service, is listed in MVA. The loading on line “L” is the power
that is redistributed between the parallel transmission system and the distribution or sub‐transmission
system when line “L” is taken out of service.
HV Line "L" out‐of‐service: Pln1, , Pln2, Pln3, Pln4
The loading on each line, with line “L” out‐of‐service, is listed in MVA.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 30
LODF
The Line Outage Distribution Factor (LODF) is the fraction of the load on line “L” that is picked up on the
distribution or sub‐transmission system. This information is included for illustrative purposes to
understand the analysis, but was not used in identifying the voltage threshold for Exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 31
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV
In the course of developing ‘real‐world’ scenarios for the analysis of potential sub‐100 kV loop flows, the
Standard Drafting Team found that the industry has employed various measures to minimize the subject
loop flows. Some of these methods that were found to be applied by entities on sub‐100 kV loop
systems are described below. However, it is important to note that the presence of the equipment in
the following examples does not remove or lessen an entity’s obligations associated with the bright‐line
application of the Bulk Electric System (BES) definition.
Sustained power flow through substation power transformers and low voltage loops is generally
undesirable and, in some instances injurious. For this reason, power system engineers typically address
this issue in their design, operating, and planning criteria and apply methods to prevent this condition
from occurring. The high impedance of transformers and low voltage elements inherently prevent
excessive flow, but in many instances this flow can exceed ratings of equipment. For these reasons
entities develop control schemes, add relaying, and provide operational and planning guidelines to
prevent this loop flow. Figure 7 depicts two systems that could provide a possible loop flow across the
low voltage system and back up to the high voltage system. The loop flow in these diagrams is increased
when the breaker on the high voltage side (breaker B) is opened.
The diagrams presented below depict a generic power system. The higher voltage and lower voltage
circuit breakers and bus arrangements will, in practice, vary (i.e., straight bus, half‐breaker, ring bus,
breaker‐and‐a‐half, etc.), but the concepts remain the same.
Specifically, Figure 7, shown below, depicts segments of an electrical power system. They consist of a
greater than 100 kV system and a sub‐100 kV system. Figure 7 depicts the power flow through the
electrical system under the condition that all circuit breakers are closed (normal condition). In the event
that circuit breaker B opens (i.e., manually, supervisory control, or protective device operation) and (1)
and either of the sub‐100 kV line circuit breakers (A or C) or (2) either of the low‐side transformer circuit
breakers (D or F) or (3) the low‐side bus tie circuit breaker (E) does not open, a condition could occur
where some amount of flow will occur through the sub‐100 kV system to the greater than 100 kV
system. This flow is severely limited by the high impedance of the two transformers in series and the
sub‐100 kV system impedance. This condition, however, may be deemed undesirable from an
equipment standpoint and precautions may be taken to prevent it. Subsequent sections of this appendix
show some of the physical schemes that entities can employ in this regard.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 32
Figure 7. Summary of Loop Flow
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 33
Interlocked Control Schemes
Interlocking control schemes can be used to prevent low voltage loop flow. One method to preclude
sustained power flow from the lower voltage to the higher voltage portion of the system is to include
control system interlocks which will cross‐trip certain circuit breaker(s) when other specified circuit
breakers are opened. This condition is generally rare since bus designs and protective relay system
operations generally do not result in this condition occurring. Operational guidelines usually instruct
personnel to avoid the use of the interlocking schemes during normal or planned switching. However,
unplanned actions can cause breakers to open and result in the desirable operation of the interlocking
schemes. This method, therefore, is considered to be conservative but, never‐the‐less, it is applied in
some instances.
Figure 8 below shows how an interlock scheme would function to prevent low voltage loop flow. When
the high side breaker (breaker B) is opened, the low side breaker (breaker E) is also opened. This action
prevents low side loop flow. The interlocking scheme could be applied in various combinations and the
figure below is a simplified illustration of such a scheme.
Figure 8. Interlocking Schemes
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 34
Reverse Power Schemes
Protection schemes can also be deployed to prevent sustained loop flows through the sub‐100 kV
system. Reverse power applications are one example of a protection scheme that prevents sustained
undesirable low voltage loop flow. In some instances, protective devices will preclude sustained loop
flows due to their settings and in other instances protective schemes are specifically applied to preclude
this undesirable operating condition.
Figure 9 below shows how a reverse power scheme would function to prevent sub‐100 kV loop flow.
When the high side breaker (breaker B) is opened, current may flow from the high voltage side (breaker
A) through the low voltage bus and back to the high voltage side (breaker C). A relay on breaker F is
applied to sense the reverse flow (relay shown in yellow in the diagram) and will operate if this flow
continues (relay shown in red in the diagram). When the reverse power relay operates it will trip
breaker F. This action prevents reverse power flow through the transformer and low voltage loop flow.
The reverse power scheme is set to sense a minimum amount of power flowing in a reverse direction
and is usually set much less than the transformer rating. The figure below is a simplified illustration of a
reverse power scheme.
Figure 9. Reverse Power Schemes
Transformer Overcurrent Limitations
Transformer overcurrent protection schemes can also be deployed to prevent sustained loop flows
through the sub‐100 kV system. Figure 10 below shows how a transformer overcurrent scheme would
function to prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current
may flow from the high voltage side (breaker A) through the low voltage bus and back to the high
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 35
voltage side (breaker C). The relay on the transformer and breaker D is applied to protect the
transformer from excessive overloads and faults on the low voltage system. If a fault occurs or the
transformer is over‐loaded then the relay on breaker D will sense this excessive flow (relay shown in
yellow in the diagram) and will operate if this flow continues (relay shown in red in the diagram). When
the transformer overcurrent relay operates it will trip breaker D. This action unloads the transformer in
question and prevents low voltage loop flow. The transformer overcurrent relay is typically set to allow
the transformer to be loaded to the emergency rating of the transformer plus a small safety margin.
The figure below is a simplified illustration of a transformer overcurrent scheme.
Figure 10. Transformer Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 36
Feeder Overcurrent Limitations
Feeder overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 11 below shows how a feeder overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage feeder, through a feeder tie, and back to the
high voltage side (breaker C). The relay on the feeder and breaker G is applied to protect the feeder
from excessive overloads and faults on the low voltage feeder. If a fault occurs or the feeder is over
loaded, the relay on breaker G will sense this excessive flow (relay shown in yellow in the diagram) and
will operate if this flow continues (relay shown in red in the diagram). When the feeder overcurrent
relay operates it will trip breaker G. This action opens the feeder breaker and prevents low voltage loop
flow. The feeder overcurrent relay is typically set to allow the feeder to be loaded to the emergency
rating of the feeder rating plus a small safety margin. The figure below is a simplified illustration of a
feeder overcurrent power scheme.
Figure 11. Feeder Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 37
Bus Tie Overcurrent Limitations
Bus tie overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 12 below shows how a bus tie overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage bus and back to the high voltage side (breaker
C). The relay on the bus tie and breaker E is applied to protect the bus from excessive overloads and
faults on the low voltage bus(ses). If a fault occurs or the bus is over loaded, then the overcurrent relay
on breaker E will sense this excessive flow (relay shown in yellow in the diagram) and will operate if this
flow continues (relay shown in red in the diagram). When the bus tie overcurrent relay operates, it will
trip breaker E. This action opens the bus tie breaker and prevents sustained low voltage loop flow. The
bus tie overcurrent relay is typically set to allow the bus to be loaded to the emergency rating plus a
small safety margin. The figure below is a simplified illustration of a bus tie overcurrent power scheme.
A
C
C
A
B
B
> 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
D
D
F
R
F
R
E
E
< 100kV
Loop Flow
Load
Load
Load
BUS TIE (Outage)
Load
Bus Tie Operate
Figure 12. Bus Tie Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 38
Custom Protection and Control Schemes
Custom protection and control schemes may also be deployed to prevent loop flows through the sub‐
100 kV system. Figure 13 below shows how such schemes would function to prevent sub‐100 kV loop
flow. When the greater than 100 kV line 1 breakers (breakers D and G) open, current may flow from the
high voltage side (breaker E) through the low voltage bus and back to the high voltage side (breaker H).
The custom scheme implemented at the substation will trip or run back generation to prevent over
loads and sustained loop flows on the low voltage system.
A
Gen 1
B
C
Line 2
F
I
D
Line 1
G
J
E
A
Gen 1
H
Gen 2
B
C
Line 2
F
I
D
Line 1
G
J
E
H
Gen 2
> 100kV
< 100kV
> 100kV
< 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
Load
Loop Flow
Load
Load
Line Outage
Load
Custom Scheme Operates to Reduce Gen
Figure 13. Custom Scheme Operations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 39
Appendix 4 Summary
The issues and methods described in Appendix 4 are reflective of why, in most instances, conditions of
sustained loop flows through sub‐100 kV systems are alleviated. When the low voltage is much less
than 100 kV, the design considerations shown above become even more pertinent and preventative
methods are employed; BES reliability is not the main concern, protecting the equipment from physical
damage is the primary concern. In the vast majority of cases, robust planning and operating criteria and
procedures will alleviate any concerns regarding sustained loop flows.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 40
E-mail completed form to:
[email protected]
Standards Authorization Request
Form
Title of Proposed Standard
definition
NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System
Request Date
December 2, 2011
SAR Type
SAR Requester Information
(Check all that apply)
Name: Project 2010-17 Definition of Bulk Electric
System (BES) SDT
Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT Chair
Telephone: (813) 207-7994
Fax: (813) 289-5646
E-mail: [email protected]
New Standard
X
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?)
This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Purpose or Goal (How does this request propose to address the problem described above?)
Research possible revisions to the definition of BES (Phase 2) to address the issues identified through
Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition encompasses all
Elements necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
Standards Authorization Request
SAR Information
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and
technically sound definition of the Bulk Electric System (BES).
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?)
Revise the BES definition to identify the appropriate electrical components necessary for the reliable
operation of the interconnected transmission network.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Collect and analyze information needed to support revisions to the definition of Bulk Electric System
(BES) developed in Phase 1 of this project to provide a technically justifiable definition that identifies
the appropriate electrical components necessary for the reliable operation of the interconnected
transmission network. The definition development may include other improvements to the definition
as deemed appropriate by the drafting team, with the consensus of stakeholders, consistent with
establishing a high quality and technically sound definition of the BES.
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.)
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.
•
•
•
•
Form
Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources necessary for the reliable operation of the Bulk Electric System (BES)
The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous
BES - Determine if there is a need to change this position
Determine if there is a technical justification to revise the current 100 kV bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
2
Standards Authorization Request
SAR Information
network under certain conditions and if so, what the maximum allowable flow and duration
should be
Provide improved clarity to the following:
•
•
•
The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources
•
The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution
Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the BES.
Based on the potential revisions to the definition of the BES and an analysis of the application of, and
the results from, the exception process, the drafting team will review and if necessary propose
revisions to the ‘Technical Principles’ associated with the Rules of Procedure Exception Process to
ensure consistency in the application of the definition and the exception process.
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
This section is not applicable as the SAR is for a definition which is about Elements, Applicability of
entities is covered in Section 4 of each Reliability Standard.
Form
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.
3
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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.
Administers the transmission tariff and provides transmission
Transmission
services under applicable transmission service agreements (e.g., the
Service Provider
pro forma tariff).
Form
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
4
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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 box for all that apply.)
X
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.
X
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.
X
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.
X
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
X
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
X
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
X
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
X
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Form
5
Standards Authorization Request
Applicable Reliability Principles (Check box for all that apply.)
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Form
Explanation
6
Standards Authorization Request
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Form
7
Meeting Minutes
Standards Committee
August 2, 2013 | 10:30 a.m. – 11:00 a.m. ET
Introductions and Chair’s Remarks
B. Murphy welcomed Committee members and observers and determined the presence of a quorum. The
attendance of Standards Committee members is provided in Attachment A.
NERC Antitrust Compliance Guidelines and Public Announcement
Kristin Iwanechko reviewed the NERC Antitrust Compliance Guidelines and reminded participants that
notice of the meeting had been widely distributed.
Agenda Items
1. Project 2012-05 ATC Revisions (MOD A)
J. Tarantino motioned to approve the slate as recommended. J. Bussman seconded the motion.
- The Committee approved the motion with no objections or abstentions.
C. Yeung noted that a nomination from the SPP region was submitted after the nomination deadline
and asked the Committee to consider the nomination. It was determined that the nominee may be
considered at a future Committee meeting.
2. Request to Waive the Standard Process for Phase 2 of Project 2010-17
J. Sterling motioned to authorize a waiver of the Standard Processes Manual to shorten the next and
any subsequent comment periods for Phase 2 of Project 2010-17 prior to the final ballot from 45 days
to 30 days, with a ballot conducted during the last 10 days of the comment period, and also require
NERC staff to post notice of the waiver on the project page and notify the NERC Board of Trustees
Standards Oversight and Technology Committee of the waiver. L. Campbell seconded the motion.
- The Committee approved the motion with no objections or abstentions.
Committee members urged NERC to ensure that the waiver was clearly communicated to industry. J.
Sterling, P. Heidrich and L. Hussey were asked to work together to develop language describing the
waiver for inclusion in the next posted project announcement.
Standards Announcement Reminder
Project 2010-17 Definition of Bulk Electric System - Phase 2
An Additional Ballot is now open through October 28, 2013
Now Available
An additional ballot for Phase 2 of the Definition of Bulk Electric System is now open through 8 p.m.
Eastern on Monday, October 28, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
definition by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual,
which requires all negative votes to have an associated comment submitted (or an indication of
support of another entity’s comments). Please see NERC’s announcement regarding the balloting
software updates and the guidance document, which explains how to cast your ballot and note if
you’ve made a comment in the online comment form or support another entity’s comment.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will
consider all comments received during the formal comment period and, if needed, make revisions
to the definition. If the comments do not show the need for significant revisions, the definition 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
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-17 Definition of the Bulk Electric System - Phase 2
Formal Comment Period: September 27, 2013 – October 28, 2013
Upcoming Additional Ballot: October 18-28, 2013
Now Available
A 30-day comment period1 for Phase 2 of the Definition of the Bulk Electric System is open through 8
p.m. Eastern on Monday, October 28, 2013.
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 Monday, October 28, 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 for the definition will be conducted as noted above.
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
1
Note that on August 2, 2013, the Standards Committee authorized a waiver of the standard process to permit the comment period that
began on August 6, 2013 as well as any subsequent comment period prior to a final ballot of Phase 2 of the Definition of Bulk Electric
System. The waiver allows the comment periods to be shortened from 45 days to 30, with a ballot during the last ten days of the
comment period. Minutes of the Standards Committee’s meeting where the waiver was considered have been posted on the NERC
website.
Standards Announcement: Project 2010-17 DBES- Phase 2
2
Standards Announcement
Project 2010-17 Definition of the Bulk Electric System - Phase 2
Formal Comment Period: September 27, 2013 – October 28, 2013
Upcoming Additional Ballot: October 18-28, 2013
Now Available
A 30-day comment period1 for Phase 2 of the Definition of the Bulk Electric System is open through 8
p.m. Eastern on Monday, October 28, 2013.
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 Monday, October 28, 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 for the definition will be conducted as noted above.
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
1
Note that on August 2, 2013, the Standards Committee authorized a waiver of the standard process to permit the comment period that
began on August 6, 2013 as well as any subsequent comment period prior to a final ballot of Phase 2 of the Definition of Bulk Electric
System. The waiver allows the comment periods to be shortened from 45 days to 30, with a ballot during the last ten days of the
comment period. Minutes of the Standards Committee’s meeting where the waiver was considered have been posted on the NERC
website.
Standards Announcement: Project 2010-17 DBES- Phase 2
2
Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Phase 2
Additional Ballot Results
Now Available
An additional ballot for Phase 2 of the Definition of Bulk Electric System concluded at 8 p.m. Eastern
on Tuesday, October 29, 2013.
The definition 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 additional ballot.
Approval
Quorum: 75.83%
Approval: 72.55%
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 definition. If the comments do not show the need for significant
revisions, the definition 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 (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
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010-17 Definition of BES - Phase 2 Oct 2013
Password
Ballot Period: 10/18/2013 - 10/29/2013
Ballot Type: Additional
Log in
Total # Votes: 298
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 393
Quorum: 75.83 % The Quorum has been reached
Weighted Segment
72.55 %
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
104
1
53
0.736
19
0.264
0
7
25
8
0.5
4
0.4
1
0.1
0
2
1
90
1
42
0.689
19
0.311
0
7
22
36
1
19
0.679
9
0.321
0
1
7
88
1
42
0.7
18
0.3
1
6
21
51
1
23
0.657
12
0.343
0
1
15
2
0.1
0
0
1
0.1
0
0
1
2
0.1
1
0.1
0
0
0
0
1
4
0.2
2
0.2
0
0
0
0
2
8
0.8
7
0.7
1
0.1
0
0
0
393
6.7
193
4.861
80
1.839
1
24
95
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
NERC Standards
Segment
Organization
Member
Ballot
1
1
Ameren Services
American Transmission Company, LLC
Eric Scott
Andrew Z Pusztai
Affirmative
Affirmative
1
Arizona Public Service Co.
Robert Smith
Negative
1
Associated Electric Cooperative, Inc.
John Bussman
Negative
1
1
1
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Affirmative
Tony Kroskey
1
1
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
John C Fontenot
John Brockhan
1
Central Electric Power Cooperative
Michael B Bax
1
1
Kevin J Lyons
Joseph Turano Jr.
Affirmative
Chang G Choi
Affirmative
1
1
1
1
Central Iowa 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
1
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
1
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
El Paso Electric Company
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
1
1
1
1
1
1
Bob Solomon
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Michael Moltane
Affirmative
Jim D Cyrulewski
Abstain
Walter Kenyon
1
1
1
1
1
1
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
John Chin
Doug Bantam
Robert Ganley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Abstain
Abstain
Affirmative
KAMO Electric Cooperative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
Affirmative
Ajay Garg
Martin Boisvert
Molly Devine
1
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Abstain
Brazos Electric Power Cooperative, Inc.
Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Michael S Crowley
Douglas E. Hils
Amber Anderson
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Affirmative
1
1
NERC
Notes
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
NERC Standards
1
Lower Colorado River Authority
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Nazra S Gladu
Danny Dees
Allan Long
Affirmative
Affirmative
1
MidAmerican Energy Co.
Terry Harbour
Negative
1
Minnesota Power, Inc.
Randi K. Nyholm
Negative
1
Minnkota Power Coop. Inc.
Daniel L Inman
Abstain
1
Muscatine Power & Water
Andrew J Kurriger
Negative
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
1
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
New York State Electric & Gas Corp.
North Carolina Electric Membership Corp.
Michael Jones
Cole C Brodine
Affirmative
Affirmative
1
1
1
1
Bruce Metruck
Raymond P Kinney
Robert Thompson
Northeast Missouri Electric Power
Cooperative
Kevin White
1
1
1
1
1
1
1
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Jen Fiegel
Brad Chase
Daryl Hanson
John C. Collins
John T Walker
David Thorne
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Kenneth D. Brown
Negative
Dale Dunckel
Abstain
1
Public Service Company of New Mexico
Laurie Williams
1
1
1
1
1
1
1
1
1
1
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (SUPPORTS
THIRD PARTY
COMMENTS (Public Service
Enterprise
Group))
Brenda L Truhe
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
COMMENT
RECEIVED
COMMENT
RECEIVED
Negative
PPL Electric Utilities Corp.
1
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted
under name of
PPL
Corporation)
1
Public Service Electric and Gas Co.
Negative
Randy MacDonald
1
1
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
NERC Standards
1
1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Tom Hanzlik
Shawn T Abrams
1
Southern California Edison Company
Steven Mavis
Negative
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tennessee Valley Authority
Howell D Scott
1
Tri-State G & T Association, Inc.
Tracy Sliman
1
1
1
1
1
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
2
BC Hydro
2
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
2
Midwest ISO, Inc.
Marie Knox
2
2
2
New Brunswick System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alden Briggs
stephanie monzon
Charles H. Yeung
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
Michael E Deloach
Negative
3
3
3
3
Alabama Power Company
Alameda Municipal Power
Ameren Services
Arkansas Electric Cooperative Corporation
Robert S Moore
Douglas Draeger
Mark Peters
Philip Huff
Abstain
Chris W Bolick
3
3
3
3
3
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
3
Central Electric Power Cooperative
Adam M Weber
3
3
3
3
3
3
3
3
3
3
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Farmington
City of Palo Alto
City of Redding
City of Tallahassee
City of Ukiah
Colorado Springs Utilities
Thomas C Duffy
Steve Alexanderson
Dennis M Schmidt
Andrew Gallo
Linda R Jacobson
Eric R Scott
Bill Hughes
Bill R Fowler
Colin Murphey
Charles Morgan
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Joe
DePoorter,
MGE)
Affirmative
Affirmative
Affirmative
AEP
Associated Electric Cooperative, Inc.
COMMENT
RECEIVED
Affirmative
Affirmative
3
3
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
from American
Electric Power)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (see AECI
comments)
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
NERC Standards
3
3
ComEd
Consolidated Edison Co. of New York
John Bee
Peter T Yost
3
Consumers Energy Company
Gerald G Farringer
3
3
3
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Russell A Noble
Jose Escamilla
Michael R. Mayer
3
Detroit Edison Company
Kent Kujala
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Dominion Resources, Inc.
East Kentucky Power Coop.
El Paso Electric Company
Entergy
Fayetteville Public Works Commission
FirstEnergy Corp.
Flathead Electric Cooperative
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
Connie B Lowe
Patrick Woods
Tracy Van Slyke
Joel T Plessinger
Allen R Wallace
Cindy E Stewart
John M Goroski
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
3
KAMO Electric Cooperative
Theodore J Hilmes
3
3
3
Kissimmee Utility Authority
Kootenai Electric Cooperative
Lakeland Electric
Gregory D Woessner
Dave Kahly
Mace D Hunter
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Jason Fortik
Negative
3
Louisville Gas and Electric Co.
Charles A. Freibert
Negative
3
M & A Electric Power Cooperative
Stephen D Pogue
Negative
3
3
Manitoba Hydro
MEAG Power
Greg C. Parent
Roger Brand
MidAmerican Energy Co.
Thomas C. Mielnik
Negative
3
Mississippi Power
Jeff Franklin
Negative
3
Modesto Irrigation District
Jack W Savage
3
3
3
3
National Grid USA
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Brian E Shanahan
Tony Eddleman
David R Rivera
Doug White
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standarsds
Review Group)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
registered
affilitiates)
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative
Inc.)
Affirmative
Affirmative
3
John S Bos
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative
Inc)
Affirmative
Lincoln Electric System
Muscatine Power & Water
COMMENT
RECEIVED
Affirmative
Affirmative
3
3
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS Gary Kruempel
MidAmerican
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
NERC Standards
3
Northeast Missouri Electric Power
Cooperative
Skyler Wiegmann
3
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Donald Hargrove
David Burke
Ballard K Mutters
John H Hagen
Terry L Baker
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
3
3
3
3
3
Snohomish County PUD No. 1
Southern California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Mark Oens
David B Coher
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Westar Energy
Bo Jones
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
James R Keller
Negative
3
Wisconsin Public Service Corp.
Gregory J Le Grave
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
Alabama Municipal Electric Authority
Raymond Phillips
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
4
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
Ronnie Frizzell
Duane S Dahlquist
Affirmative
4
Buckeye Power, Inc.
Manmohan K Sachdeva
4
4
4
4
Central Lincoln PUD
City of Austin dba Austin Energy
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Shamus J Gamache
Reza Ebrahimian
Nicholas Zettel
John Allen
Affirmative
Affirmative
Affirmative
Affirmative
Margaret Powell
Affirmative
Consumers Energy Company
Tracy Goble
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
COMMENT
RECEIVED
Affirmative
Wisconsin Electric Power Marketing
4
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
3
4
SUPPORTS
THIRD PARTY
COMMENTS (NIPSCO)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Barbara
Kedrowski,
Wisconsin
Electric Power
Co)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Breene,
WPSC)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy's)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Jerry
NERC Standards
Farringer)
4
4
4
4
4
4
4
Cowlitz County PUD
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Rick Syring
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Diana U Torres
Jack Alvey
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
4
Integrys Energy Group, Inc.
Christopher Plante
Negative
4
Madison Gas and Electric Co.
Joseph DePoorter
Negative
4
Modesto Irrigation District
Spencer Tacke
Negative
Barry R. Lawson
Abstain
4
4
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
Cecil Rhodes
Affirmative
4
North Carolina Electric Membership Corp.
John Lemire
4
4
4
4
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Affirmative
Affirmative
4
4
4
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
4
4
Tacoma Public Utilities
Utility Services, Inc.
Keith Morisette
Brian Evans-Mongeon
4
Wisconsin Energy Corp.
Anthony Jankowski
4
WPPI Energy
Todd Komplin
5
AEP Service Corp.
Brock Ondayko
5
Amerenue
Sam Dwyer
5
Arizona Public Service Co.
Scott Takinen
5
Arkansas Electric Cooperative Corporation
Brent R Carr
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (North Carolina
Electric
Membership
Corporation)
SUPPORTS
THIRD PARTY
COMMENTS (B. GalbraithSeminole
Electric
Cooperative.)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Barb
Kedrowski, We
Energies)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
– American
Electric Power)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Cooments
provided by
AZPS)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
Negative
5
5
5
5
BC Hydro and Power Authority
Black Hills Corp
Bonneville Power Administration
BP Wind Energy North America Inc
Clement Ma
George Tatar
Francis J. Halpin
Carla Holly
Abstain
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Tom Breene –
WPSC)
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Buckeye Power, Inc.
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
Shari Heino
Chifong Thomas
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Michael Shultz
Wilket (Jack) Ng
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
5
Consumers Energy Company
David C Greyerbiehl
5
5
5
Cowlitz County PUD
CPS Energy
Dairyland Power Coop.
Bob Essex
Robert Stevens
Tommy Drea
5
Detroit Edison Company
Alexander Eizans
Negative
5
5
5
Marcus Ellis
Mike Garton
Dale Q Goodwine
Affirmative
Affirmative
Affirmative
5
5
5
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
Essential Power, LLC
Exelon Nuclear
5
5
5
5
5
5
5
5
5
5
5
Negative
Affirmative
Dana Showalter
Abstain
Gustavo Estrada
Patrick Brown
Mark F Draper
Affirmative
First Wind
John Robertson
Negative
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
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Lincoln Electric System
Dennis Florom
5
5
5
Karin Schweitzer
Rick Terrill
S N Fernando
Affirmative
Affirmative
David Gordon
Affirmative
5
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Steven Grego
Affirmative
5
Muscatine Power & Water
Mike Avesing
Negative
5
5
5
Nebraska Public Power District
New York Power Authority
NextEra Energy
Don Schmit
Wayne Sipperly
Allen D Schriver
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
COMMENT
RECEIVED Kent Kujala of
Detroit Edison
SUPPORTS
THIRD PARTY
COMMENTS (AWEA)
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (Gerry
Farringer,
Consumers
Energy)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standards
Review Group)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (North Carolina
Electric
NERC Standards
5
Northern Indiana Public Service Co.
William O. Thompson
Negative
5
5
5
5
5
5
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Pacific Gas and Electric Company
Michelle R DAntuono
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
David Ramkalawan
Richard J. Padilla
Affirmative
Affirmative
5
PacifiCorp
Ryan Millard
Negative
5
5
Pattern Gulf Wind LLC
Portland General Electric Co.
Grit Schmieder-Copeland
Matt E. Jastram
Negative
5
PPL Generation LLC
Annette M Bannon
5
5
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
Tim Kucey
Steven Grega
5
5
5
5
5
5
Membership
Corporation)
COMMENT
RECEIVED see
NIPSCO Joe
O'Brien's
comments
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
5
5
Snohomish County PUD No. 1
South Feather Power Project
Sam Nietfeld
Kathryn Zancanella
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
5
Southern California Edison Company
Denise Yaffe
Negative
5
Southern Company Generation
William D Shultz
Negative
5
5
Tacoma Power
Tennessee Valley Authority
Chris Mattson
David Thompson
Affirmative
Affirmative
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
5
5
U.S. Army Corps of Engineers
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Melissa Kurtz
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Refer to SCE's
comment)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
COMMENT
RECEIVED
Affirmative
5
Wisconsin Electric Power Co.
Linda Horn
Negative
5
Wisconsin Public Service Corp.
Scott E Johnson
Negative
6
AEP Marketing
Edward P. Cox
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Bret Galbraith
on behalf of
Seminole
Electric
Cooperative
Inc.)
SUPPORTS
THIRD PARTY
COMMENTS (Barbara
Kedrowski,
Wisconsin
Electric Power
Co.)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Breene WPSC)
NERC Standards
6
APS
Randy A. Young
6
Arkansas Electric Cooperative Corporation
Keith Sugg
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
6
6
6
6
6
6
6
6
6
6
6
6
6
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
Florida Power & Light Co.
Great River Energy
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
Silvia P Mitchell
Donna Stephenson
6
Lincoln Electric System
Eric Ruskamp
6
6
6
6
6
6
6
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern California Power Agency
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Matthew Schull
Steve C Hill
6
Northern Indiana Public Service Co.
Joseph O'Brien
6
Oklahoma Gas & Electric Services
Jerry Nottnagel
6
PacifiCorp
John Volz
6
6
6
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Carol Ballantine
Ty Bettis
Stephen C Knapp
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED Ryan Millard
Affirmative
6
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
6
6
6
6
Public Utility District No. 1 of Chelan County Hugh A. Owen
Sacramento Municipal Utility District
Diane Enderby
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown
Seattle City Light
Dennis Sismaet
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
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SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standards
Review Group)
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS Christina
Koncz PSEG (PSEG Submitted by
John Seelke)
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Bret Galbraith
will be
submitting
comments on
behalf of
Seminole
Electric
Cooperative,
Inc.)
NERC Standards
6
6
Snohomish County PUD No. 1
Southern California Edison Company
Kenn Backholm
Lujuanna Medina
Affirmative
6
Southern California Edison Company
Joseph T Marone
Negative
6
Southern Company Generation and Energy
Marketing
John J. Ciza
Negative
6
6
6
6
6
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Peter H Kinney
Affirmative
6
Wisconsin Public Service Corp.
David Hathaway
Negative
6
Xcel Energy, Inc.
David F Lemmons
Negative
7
Alcoa, Inc.
Thomas Gianneschi
Negative
7
8
8
9
Thomas W Siegrist
Edward C Stein
Debra R Warner
Bruce Lovelin
Affirmative
Affirmative
Donald Nelson
Affirmative
9
10
EnerVision, Inc.
Central Lincoln PUD
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Florida Reliability Coordinating Council
10
Midwest Reliability Organization
Russel Mountjoy
10
10
10
10
10
10
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
9
9
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (Please Tom
Breene's
comments
submitted on
behalf of
Wisconsin
Public
Service.)
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel Energy)
COMMENT
RECEIVED
Diane J. Barney
Thomas G. Dvorsky
Linda Campbell
Affirmative
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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
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NERC Standards
https://standards.nerc.net/BallotResults.aspx?BallotGUID=eb3fe15e-4b87-4534-b96c-1159ca034634[10/30/2013 11:47:05 AM]
Individual or group. (40 Responses)
Name (27 Responses)
Organization (27 Responses)
Group Name (13 Responses)
Lead Contact (13 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (2 Responses)
Comments (40 Responses)
Question 1 (35 Responses)
Question 1 Comments (38 Responses)
Question 2 (31 Responses)
Question 2 Comments (38 Responses)
Individual
Bangalore Vijayraghavan
Pacific Gas and Electric Comapny
Yes
We support the definition as posted and commend the drafting team for considering the
comments from the industry and weighing those industry comments against the FERC
directives. Many of the industry comments take a different direction and opinion from the
FERC directives and we recognize that the definition is a compromise on the positions of all
stake holders. It provides a bright line that will improve reliability and provide a consistent
process across North America to address exceptions.
No
Individual
John Falsey
Invenergy LLC
Agree
AWEA
Individual
Thomas Foltz
American Electric Power
Yes
Yes
AEP cannot vote in the affirmative on this project as long as BES elements (measured for
compliance) are as granular as the individual dispersed power resource. We do not see the
reliability benefit (nor has the project team provided technical justification) of tracking all of
the compliance elements for individual wind turbines when the focus should be placed on the
aggregate of the facility. Does the RC want to be notified of an outage of each individual wind
turbine in real-time, or a loss of significant portion of the wind farm? If we are not careful, we
will have entities at these resources and others monitoring them (BAs, TOPs, RCs) focusing on
minor issues that will distract from more relevant reliability needs.
Group
Northeast Power Coordinating Council
Guy Zito
No
The use of the word “capacity” is a concern. Generators might not be considered BES under
the definition. Suggested change to I4 as follows: I4 - Dispersed power producing resources
that aggregate to a gross total nameplate rating greater than 75 MVA, and that are connected
through a system designed primarily for delivering such energy to a common point of
connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are: a) The
individual resources, and b) The system designed primarily for delivering energy from the
point where those resources aggregate to greater than 75 MVA to a common point of
connection at a voltage of 100 kV or above.
No
Individual
David Jendras
Ameren
Yes
Yes
(1) When the SDT updates the Reference (Guidance) Document, we request a couple of
additions to help clarify Exclusion E3. We ask the SDT to include System Diagram examples
with a 138kV Local Network (LN) for which Real Power only flows in (from 138 to 69kV) and
embedded within this LN is a 69kV network with multiple generating units. Note that none of
these generators are Blackstart Resources or Dispersed power resources. We believe that the
left side of your Figure S1-9b could be adapted to do this. Please add the two following
examples: (a) First, a 69kV network that serves load at multiple substations and has three
different substations each with a single 13.8/69kV GSU for a single 19MVA generator with an
aggregate capacity of (3 x 19 MVA =) 57MVA within the entire 138kV LN; and (b) Second, the
same diagram as item 1a plus one additional single 13.8/69kV GSU for a single 50MVA
generator to provide an aggregate capacity of (3 x 19 MVA + 50 MVA =) 107MVA within the
entire 138kV LN . Our understanding is that the 138kV leads to the 138/69kV transformers
are all excluded via Exclusion E3; and that neither the entire 69kV network nor any of the
embedded generation (aggregate 57 MVA for the first example or 107MVA for the second
example) should be included by any BES Inclusion. (2) When the SDT updates the Reference
(Guidance) Document, we request one additional item to help clarify Inclusion I2. We ask the
SDT to add a new Figure I2-7 similar to Figure I2-6. In this new Figure I2-7, we request that the
>100kV / <100kV transformer on the right be removed and connected to another <100 kV
location in the network. The generator on the right with GSU high side <100kV should be
changed from 25 MVA to 88 MVA. This generator is neither a black-start resource nor a
dispersed power resource and therefore should not be included by Inclusions I3 or I4, and our
understanding is that the 88 MVA generator is also not included by Inclusion I2.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
No
The definition should not apply to individual dispersed units that are less than 5 MW because
independent units less than 5 MW are too small to have an impact on the BES.
Yes
Everything that has been excluded from the BES definition should also be excluded from I5 for
reactive sources, because there is no impact to the BES. For example, if a radial system (E1) is
excluded because it does not have an impact on the BES, a reactive resource connected at the
end of the radial system is not likely to have an impact on the BES either.
Individual
Joe O'Brien
NIPSCO
Yes
We appreciate your consideration of our previous comments and a draft interpretation
However since such interpretations and a guidance document are already being developed
for this draft standard, more clarification is probably needed within the standard itself.
Individual
Kathleen Goodman
ISO New England, Inc.
No
The use of the word “capacity” is a concern. Below is suggested language. I4 - Dispersed
power producing resources that aggregate to a total gross nameplate rating greater than 75
MVA, and that are connected through a system designed primarily for delivering such energy
to a common point of connection at a voltage of 100 kV or above. Thus, the facilities
designated as BES are: a) The individual resources, and b) The system designed primarily for
delivering energy from the point where those resources aggregate to greater than 75 MVA to
a common point of connection at a voltage of 100 kV or above.
Individual
Russell A Noble
Cowlitz PUD
No
We understand the difficulty of backtracking on past progress. We have voted in the
affirmative for the greater objective of not impeding the overall positive progress of the
definition. However, we acknowledge the industry has identified a valid concern over I4, and
although the SDT is powerless to correct the issue, it is important to record and document
reservations so future efforts in standard development may be facilitated to correct problems
with compliance overreach. Most of the I4 facilities that will be included into the BES
inherently work against reliability, and this characteristic can’t be mitigated by adherence to
the current GO/GOP standards in place. For example, assuring an individual generator
protection system of a wind/solar unit will not misoperate adds little protection to the BES
when the unit is frequently down due to insufficient wind or sunshine. It is a fact that such
generation can’t be designated as must run, and instead other generation units which can be
dispatched must be available on demand to replace lost wind/solar resources. Therefore, we
admonish FERC and NERC to recognize the true nature of wind and solar resources as an
effort to reduce carbon footprint on the environment and are not intended to replace
dispatchable generation, and that compliance without any reliability return should be
removed to facilitate its development.
No
Individual
Kenneth A Goldsmith
Alliant Energy
No
No
No - Alliant Energy still believes strongly that including individual dispersed generators (I4) as
part of the BES does nothing to maintain/increase the reliability of the BES, and creates an
extremely difficult compliance process. It will also create a very large backlog of exception
requests, as most dispersed generator owners will request an exception for their generators.
Individual
Gerald G Farringer
Consumers Energy
No
The inclusion and the clarification of the inclusion seem to contradict each other. The
highlight portion above seems to indicate inclusion only from the point of aggregation of
75MVA or above. This, in most Wind Park cases would include a collector bus but probably
not individual wind turbines. However I4 seems to indicate that the case of a Wind Park that
has a total aggregation of 75 MVA, all associated equipment including every individual wild
turbine would be included. There is inconsistency. Technical justification should be needed to
include resources in the BES, not the other way around. Is there a real expectation that a
single collector circuit containing ten, 1.2MW wind turbines can cause cascading or
uncontrollable outages of the surrounding system? It is extremely doubtful. Consumers
Energy supports the inclusion of equipment where the aggregation of 75 MVA or more
connects to the Bulk Electric System at voltages of 100kv or greater. There is a clear indication
here that a single contingency can remove the total of the capacity from the system where
with the proposed inclusion does not. Administrative burden and compliance risk must be
weighed against reliability gain. Including individual wind turbines rather than the aggregate
of the wind farm increases such burden without any reliability gain.
No
Individual
Joseph G DePoorter
Madison Gas and Electric Company
No
MGE does not understand why individual dispersed power resources remain to be include as
we clearly stated during the last comment period. The SDT has stated that no technical
rational to support there removal. FAC-001 and FAC-002 are mandatory enforceable
Standards that entity's must follow. These Standards provide the justification as pointed out
in our last set of comments. The SDT has stated in order to fix this, an addition SAR would be
submitted (such as the GOTO) to "fix" this issue. Why would the ERO what to expend
resources to fix something after the fact when the SDT has the ability to fix it now. The
removal of I4a will solve this issue. If individual resources need to be in based on system
instability issues, then this can be addressed at a later date, once it is proven that individual
resources need to be considered part of the BES and the individual resources cause BES
instability.
No
Group
North Carolina Electric Membership Corporation
Scott Brame
No
We have voted affirmative for this project in the past but are now changing our vote to
negative based on the changes made to I4. We feel that the drafting team has further
complicated the BES definition by the proposed language in Inclusion I4. According to the
Phase 1 definition, dispersed power producing units would only be included if the units
reached the 75 MVA aggregate threshold. There is nothing in the Phase 1 definition that
would include collector system equipment. The Phase 2 definition is problematic because
there is uncertainty regarding the scope of equipment that that would be included as a
portion of the collector system. This ambiguity has raised concerns that regional compliance
staff may ultimately determine a different set of equipment is included in the BES than the
registered entity will leaving the burden on the registered entity to argue why certain
elements should not be included in the BES. This will lead to inconsistent compliance
outcomes. We cannot support a definition with vague and ambiguous language that could
result in negative compliance implications during registration, audits, and enforcement
processes. Furthermore, we do not believe any part of the collector system should be
included in the definition.
No
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
No
Individual
Nazra Gladu
Manitoba Hydro
Yes
No
Individual
Marie Knox
MISO
Agree
Madison Gas & Electric
Individual
Alice Ireland
Xcel Energy
No
In several prior comment periods, we have asked many technical questions of the BES SDT,
and continue to get generic non-substantive replies. While a majority of our questions still
remain unanswered, we have elected to not submit them again. However, we believe it is
especially important to understand the SDT’s response to this question. When considering a
wind farm that would qualify as BES under the currently drafted version, it seems inconsistent
that a 2 MVA individual dispersed generator is deemed significant to reliability, while the
equipment that is utilized to connect a sub-set of the individual dispersed generators totaling
to <75 MVA is deemed not significant to reliability. Please explain the technical rationale for
concluding that an individual dispersed generating asset rated at 2 MVA is important to grid
reliability but that a collector feeder for a sub-set of these generators which may impact up to
35 (70 MVA) of these individual dispersed generating assets is not critical to reliability?
Yes
2. We appreciate that the BES SDT acknowledges that numerous existing and pending
standards will need to be reviewed and revised to clarify standard applicability to individual
generating units. However, we do not believe that implementation of the BES definition
should go forward until this review and revision of other standards has been completed.
Therefore, we recommend the implementation plan for the BES definition be contingent
upon the completion of modification to applicable GO/GOP requirements. Otherwise, there
will simply be too much ambiguity in the requirements as they apply to individual dispersed
generating assets, there will be too much compliance effort spent on trying to apply these
ambiguous requirements with no commensurate gain in reliability, and in the end many of
the requirements will change and possibly no longer apply.
Individual
Thomas Breene
WPSC
No
As our previous comments have indicated, we agree with including the Generating stations
with dispersed generation from the point of aggregation to 75 MVA as I4-b does. We also
agree with the statement made on the BES Phase II webinar of August 21 that this is the point
where the dispersed power plant is significant to the reliability of the BES. We continue to
disagree with including the individual resources themselves since, as indicated on the
previously referenced webinar, they are not significant to the reliability of the BES. The
technical rationale for not including dispersed power producing resources has been included
in many past comments and will not be restated here. Compliance with most protection
system and equipment rating standards is not possible for individual BES wind turbines
without revisions to the standards, or at best without significant resources to apply existing
standards to individual units. Some of the standards effected include PRC-004-2a, FAC-001,
FAC-003, FAC-008-3, MOD-024, MOD-025, MOD-026, MOD-027, PRC-005, PRC-006-SPP-01,
PRC-019, PRC-024, PRC-025, and TOP-003. But we continue to stress that including an I4a will
require significant resources in personnel and modifications or result in fast-tracking Standard
changes to make compliance possible with no improvement in reliability of the BES. These
resources would be better utilized elsewhere to actually improve reliability.
No
Group
ACES Standards Collaborators
Ben Engelby
No
We feel that the drafting team has further complicated the BES definition by the proposed
language in Inclusion I4. According to the Phase 1 definition, dispersed power producing units
would only be included if the units reached the 75 MVA aggregate threshold. There is nothing
in the Phase 1 definition that would include collector system equipment. The Phase 2
definition is problematic because there is uncertainty regarding the scope of equipment that
that would be included as a portion of the collector system. This ambiguity has raised
concerns that regional compliance staff may ultimately determine a different set of
equipment is included in the BES than the registered entity will leaving the burden on the
registered entity to argue why certain elements should not be included in the BES. This will
lead to inconsistent compliance outcomes. We cannot support a definition with vague and
ambiguous language that could result in negative compliance implications during registration,
audits, and enforcement processes. Furthermore, we do not believe any part of the collector
system should be included in the definition.
No
Individual
Patrick Farrell
Southern California Edison Company
No
Phase 2 of the BES definition characterizes dispersed power producing resources as being
“small-scale” power generation technologies. However, although this characterization is
currently the norm, that could easily change in the future. As written, I4 creates an ambiguity
for Dispersed Power Producing Resources that are greater than or equal to 75MVA, because
these generation resources appear to be included within the BES under both the I2 and I4
inclusions. The problem this creates is that I2 and I4 address the connection facilities
differently, with I2 beginning at the generator terminals, while I4 begins at the point where
the resources aggregate to greater than 75 MVA. SCE believes that the SDT should clarify
which of these inclusions should apply to dispersed power producing resources greater than
or equal to 75MVA. SCE is also concerned about how I4 could potentially discourage the
development of common points of interconnection (i.e. collector substations) for multiple
projects in queue, especially in relation to the E1 and E3 exclusions. In SCE’s experience,
“plans of service” that include common collector substations for multiple generation projects
can be an effective way to encourage development of renewable resources in renewable-rich
areas. However, such resources develop and interconnect as individual projects under
separate development paths. The first distributed generation projects connecting to such
stations may find their resources initially classified as non-BES if the aggregate generation is
less than 75 MVA. However, later projects connecting to the same common point could find
the BES status changing as additional generation projects materialize at the same collector
substation. SCE is concerned that this will discourage dispersed generation developers from
pursuing common points of interconnection at collector substations built for such purpose in
renewable rich areas. The aggregate total of the projects further down the interconnection
queue could also trigger system upgrades, based on TPL studies for which the owners of
these projects would be responsible.
Yes
The 75 MVA hurdle is nothing more than an arbitrary number being used to denote/provide a
threshold for identifying the amount of generation that has a significant effect on the BES.
This number does not consider the most significant part of what should be encapsulated in
the definition which is what the “function” of the facility(ies) are with respect to a bulk
electric system operated as an integrated network.
Individual
Thomas Gianneschi
Alcoa, Inc.
Yes
An additional concern the standards development team has not adequately addressed is the
technical justification for placing compliance requirements on newly registered industrial
facilities resulting from the adoption of this definition.
Group
SPP Standards Review Group
Robert Rhodes
No
While we understand that FERC has basically directed the drafting team to include individual
dispersed power producing units in the BES, we are concerned about the need for
coordination between drafting teams for other reliability standards, such as PRC-004, PRC005, FAC-008, etc, which may be impacted by the inclusion of these generating units into the
BES. Have steps been taken to ensure that this coordination has taken place?
No
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia
Wayne Johnson
No
Eliminate Inclusion I4.a. If an individual generating element of a dispersed power producing
facility is 20 MVA or larger at a facility rated at 75 MVA or larger it should be included. At
Inclusion I4.b, Southern disagrees with the premise that BES elements (measured for
compliance) should be applied to the individual dispersed power elements. We do not see the
reliability benefit of tracking all of the compliance elements for individual wind turbines when
the focus should be placed on the aggregate of the facilities. The proposed approach is similar
to applying NERC requirements to the individual coils of a large generator. The subject
inclusion should limit the applicability of the BES to the collector bus and the capacity at this
point should be 75 MVA or greater to qualify as a BES element.
Yes
Southern Transmission believes that Exclusion E3 should include a limit on the size of a Local
Network (LN). The facilities that will comprise these LNs are currently part of the BES and
subject to all applicable standards. To allow these facilities to now be excluded from the BES
without regard to some size limitation could result in negative impacts on the BES in the
future. Southern Transmission believes that without placing a size limitation on such a
network, a single contingency could result in significant flows across the BES to serve the LN
from a different location. Additionally, there is concern that the exclusion has no requirement
for power to only flow into the LN for N-1 conditions. Southern Transmission does agree that
there may be limited locations where such an exemption could be appropriate, but would
prefer to see the facilities initially included in the BES and have the Transmission Owner go
through a review process with the Regional Reliability Organization to provide justification for
classifying facilities as a LN.
Individual
Gary Kruempel
MidAmerican Energy Company
No
MidAmerican continues to believe that individual dispersed generating units should be
excluded from Inclusion I4 of the revised BES definition. MidAmerican does not agree with
the SDT’s characterization in the question that no technical rationale was offered by any
stakeholder to support removal of the individual units from Inclusion I4. It is MidAmerican’s
understanding that at least several commenting entities have provided sound technical
arguments to support the exclusion of individual dispersed generating units. While it may be
the case that the SDT does not believe the technical justifications offered by entities have
been compelling, the SDT has not provided a complete analysis to the industry refuting each
of the technical arguments provided by registered entities. After all, a primary objective of
Phase II of the BES definition project was to carefully consider additional technical arguments
that would further refine the revised definition, including with regard to individual dispersed
generating units. MidAmerican agrees with the SDT that one suitable solution to address the
inclusion of individual dispersed generating facilities may be via adjustments to individual
standards’ applicability sections. For example, Reliability Standard MOD-025-2 (pending
approval at FERC) includes a provision addressing real power testing for variable generating
facilities. In order to accomplish the recommended case-by-case review, however, a Standard
Authorization Request would likely need to be prepared to commence the NERC standards
development process for each potentially impacted standard. In that case, it is more
appropriate and efficient to exclude such facilities from Inclusion I4 and then initiate changes
to a limited number of impacted standards that should actually apply to individual dispersed
generators, rather than initiate individual projects to modify a larger pool of standards for
which the application to such generators is not appropriate to promote reliability.
No
Individual
Randi Nyholm
Minnesota Power
No
Minnesota Power does not believe that 2 MW generators, whether or not they aggregate to
75 MW, should be included in the definition of Bulk Electric System when the distribution
transformers that control multiple units are not included. Furthermore, a non-contiguous
Bulk Electric System is problematic for maintaining reliability.
Group
Dominion
Louis Slade
Yes
No
Individual
Don Streebel
Idaho Power Co.
Yes
Yes
While we still do not agree with the categorical inclusion of individual dispersed power
producing units into the BES, we do recognize the SDT's good faith effort to comply with FERC
Orders 773 and 773-A. We understand that modeling of dispersed power producing resources
in WECC base cases will follow regional requirements governed by regional standards.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
Yes
These comments are submitted on behalf of the following PPL NERC Registered Affiliates
(PPL): Louisville Gas and Electric Company and Kentucky Utilities Company; PPL Electric
Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL Susquehanna, LLC; and
PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO,
NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP,
GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP. 1. The PPL NERC Registered Affiliates
previously commented that the language of the proposed BES definition is subject to multiple
interpretations and is therefore difficult to apply correctly without the Reference Document.
The Reference Document is not complete or final for the Phase 2 BES definition, however.
The Reference Document contains a disclaimer on p.1 that states “…this reference document
is outdated. Revisions to the document will be developed at a later date to conform to the
definition being developed in Phase 2.” In response to the PPL NERC Registered Affiliates’
concerns regarding the unavailability of a Reference Document to reflect the Phase 2 BES
definition, the SDT stated in response that it “did not intend the posted version to represent a
full implementation of Phase 2 as Phase 2 isn’t complete.” The PPL NERC Registered Affiliates
are concerned by this response because, unless it is clarified, the existing Phase 1 Reference
Document could be interpreted to bring into the Phase 2 BES definition facilities that are not,
and do not need to be, part of the BES. For example, the words in the existing Reference
Document may imply that NERC registration for very small, standby, non-Blackstart Resource
generators feeding the auxiliary buses of generation plants for emergency purposes is
required. Specifically, Figure I2-5 of the Reference Document states that all units in a plant
are part of the BES regardless of size, if the plant totals more than 75 MVA, if they "contribute
to the gross aggregate rating of the site." The SDT said in response to our earlier comments
regarding small standby diesels that, “The intent of the SDT is that the precedent will not
change how the identified equipment is classified.” However, Figure I2-5 of the Reference
Document appears to do exactly that. If for example a 500 MW plant has a 2 MW diesel
generator feeding the 4kV bus for emergency purposes (but not as a Blackstart Resource), the
facility could be said to have a gross aggregate nameplate rating of 502 MW when the diesel
is running – the aggregate nameplate rating has increased. Fig. I2-5 moreover includes in the
BES units that feed transformers with a high-side voltage less than 100 kV, if their output is
eventually stepped-up to a plant outlet that is > 100 kV. While, one could cite Fig. S1-9b,as
indicating that generators feeding a bus that is exclusively an importer of power are not part
of the BES, it would be far better to state matters explicitly in the first place. The contributeto-aggregate-capability language of the present (and outdated) Reference Document does
not appear in the BES definition and it is unclear. Item I2b of the BES definition should
therefore be accompanied by a footnote saying that, “Standby and emergency generators
that feed auxiliary buses are not considered in determining the plant/facility aggregate
nameplate rating,” or “Standby and emergency generators are not considered in determining
the plant/facility aggregate nameplate rating if they feed an auxiliary bus that is a net
importer of power.” Further, an example should be added to the Resource Document that
shows that Emergency Diesels and standby units that feed auxiliary buses that are net
importers of power are not part of the BES (unless they are Blackstart Resources). 2. The PPL
NERC Registered Affiliates also previously commented that the generic term "nameplate
rating" should be replaced by the NERC-defined term "Facility Rating." The SDT declined to
make this change, because it stated Facility Ratings, “fluctuate from period to period. “ The
PPL NERC Registered Affiliates continue to believe that the use of the term “Facility Rating” is
more appropriate. Consider for example four simple-cycle CTs rated at 19 MVA each (76 MVA
total) that are connected to a 115 kV line through a single GSU rated at 72 MVA. This in a 72
MVA plant (because of the most limiting component) and would therefore not presently be
part of the BES, but it could be pulled-in depending on whether one focuses on the
nameplate rating of the generators or the most-limiting component (in this case the GSU).
The Reference Document suggests that the former approach applies, because in every single
depiction of generation units it cites only generator ratings and ignores GSU capability.
Furthermore, using generator nameplate ratings can in certain circumstances lead to
confusion because some generators (e.g., simple cycle CTs) can have multiple ratings (e.g.,
baseload, peaking and emergency ratings). To avoid this confusion, the proposed definition
should be based on the “nameplate rating of the most-limiting component,” which in the
example here presented is 72 MVA (and is also the Facility Rating). Therefore, Inclusion I2
should be revised to read as follows: a) Gross nameplate rating of the most-limiting
component of an individual unit greater than 20 MVA, Or, b) Gross aggregate nameplate
rating of the most-limiting component(s) of a plant/facility greater than 75 MVA Additionally,
the Reference Document should be changed to provide at least one example of GSU MVA
values setting the most limiting criterion.
Individual
Barbara Kedrowski
Wisconsin Electric Power Company
No
Wind generators and solar panels are intermittent resources that are not as dependable as
other sources for supporting grid reliability. A sudden drop in wind speed or solar intensity
will instantaneously reduce the MW output of all the individual wind turbines or solar panels
in the area. It follows then that a single wind turbine or solar panel could not be an Element
or Facility necessary for the reliable operation and planning of the interconnected bulk power
system. However, common mode failure of multiple turbines or solar panels could be
significant to the reliability and planning of the BES. Efforts should be focused on preventing /
mitigating the loss of multiple generators with an aggregated capacity of greater than
75MVA. Therefore the elements necessary for the reliable operation and planning of the
interconnected bulk power system are the devices that are located where the power is
aggregated, and not the individual generators. If individual small generators that are a part of
an aggregated facility of 75 MVA or larger (e.g. a 75 MVA wind or solar farm) are considered a
part of the BES due to that aggregation, the NERC Standard requirements should only be
applied to the aggregation (e.g. the interconnection with the transmission system) and should
not be applied to individual generators of less than 20 MVA. This would be consistent with
the NERC registration criteria for single and multiple generators at a site.
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
No
The drafting team has proposed revised changes to a requirement concerning distributed
generation. In particular, when distributed generation, e.g., wind turbines, accumulate to
more than 75 MVA, only the turbines and the equipment collecting/transferring more than 75
MVA is covered as BES equipment. This allows for scenarios where non-BES equipment might
be located between two separate groups of BES equipment. Seminole does not believe this is
FERC’s intent. Seminole acknowledges that FERC did not specifically address distributed
generation in past orders when attempting to correct the BES language that resulted in
having non-BES equipment separate groups of BES equipment. However, Seminole does not
believe the drafting team’s reasoning is sufficient for this exception. Seminole believes that all
of the equipment in this scenario should be either BES-regulated or non-BES (non-NERC)
regulated.
Additionally, Seminole is re-submitting the following comments from past ballots, because
Seminole still believes that these comments are practical requests that should be
incorporated into the BES definition. (1) The terms “plant” and “facility” are not defined and
are ambiguous. Please provide quantitative and/or qualitative factors that an entity can
utilize in determining what is a plant or facility. See Inclusion I2. Seminole acknowledges that
there is draft guidance covering these terms; however, Seminole reasons that descriptive
language covering these terms should be passed in conjunction with the BES definition. (2)
The following note will be placed in the Reference document: “Dispersed power producing
resources are small-scale power generation technologies using a system designed primarily
for aggregating capacity providing an alternative to, or an enhancement of, the traditional
electric power system.” Please strike the phrase “or an enhancement of,” as it is more of a
persuasive statement than an objective statement. (3) In Exclusion E1(c), please clarify that
reactive devices, such as capacitor banks, can also be included in this section. Reactive
devices are differentiated from real power devices in Inclusion I2, so we request clarification
that reactive devices can be included in Exclusion E1(c), i.e., please add clarification to the
definition.
Group
Duke Energy
Michael Lowman
Yes
Duke Energy supports the proposed clarifications to I4 made by the SDT.
No
Individual
Michael Goggin
American Wind Energy Association
No
1. The technical rationale for not including individual generators in the BES definition is that
these individual generators cannot affect BES reliability. Whatever technical rationale drove
the drafting team’s decision to not include the collector array components in the BES
definition would also dictate that the individual turbines connected by that collector array
should also not be included in the BES definition. We cannot think of any technical rationale
that would justify including individual wind turbines in the definition but not including the
collector array that aggregates those individual generators. Regardless, the burden for
providing technical rationale should fall on the drafting team to demonstrate that including
individual generators will improve electric reliability. That burden has not been met, and the
standards drafting team has made no attempt to provide that rationale, despite repeated
requests to do so. As explained below, that burden cannot be met, as there is no benefit to
including individual generators, and including them in the definition is only likely to provoke
significant confusion that distracts from real efforts to improve electric reliability. The only
compelling reason for applying BES standards to individual dispersed generators would be if
there were a real risk of an abrupt common mode failure affecting a large share of the
dispersed generators in a >75 MVA wind plant. However, per FERC Order 661A, wind turbine
generators already comply with voltage and frequency ride-through standards that are far
more stringent than those that apply to other types of generators. As a result, if a common
mode failure caused by a grid disturbance were to affect the wind turbines in a >75 MVA
wind plant, the impact on the wind plant would be irrelevant for grid reliability because the
voltage and/or frequency deviation would have already caused most if not all of the
conventional generators in the grid operating area to trip offline. While weather-driven
changes in wind speed can significantly change the aggregate output of a wind plant, those
changes in output occur too gradually to pose a risk to bulk power system reliability, and
regardless such changes in output would not be regulated or mitigated by BES-relevant
standards. No compelling rationale has been offered for why including individual dispersed
wind turbine generators in the BES definition will improve grid reliability. Until one is offered,
we will continue to oppose the inclusion of individual wind turbine generators in the BES
definition. 2. We request clarification on the intent of the FERC direction provided in Orders
773 and 773-A regarding inclusion of dispersed generation, as we disagree with the standards
drafting team’s interpretation that those orders required the inclusion of individual dispersed
generators. After careful study, it appears that the proposed standard for the I4 inclusion of
dispersed generation is broader in scope than the intent as stated in the Orders. The critical
language appears in Order 773-A, under item number 54. Here, FERC approves the dispersed
power inclusion I4, “…finding it provides useful granularity…”, and that it agreed it is
appropriate “to expressly cover dispersed power producing resources utilizing a system
designed primarily for aggregating capacity.” We believe that the second sentence should be
further examined for proper intent. Our interpretation of this sentence is that collector
systems aggregating dispersed power at a level of 75 MVA or more is the level of intended
inclusion. This means that, in the example of a wind farm larger than 75 MVA, the application
of the BES definition and all the requisite applicable standards is only at points where the
aggregated capacity is greater than 75 MVA. This interpretation has several advantages: it is
consistent with the current output threshold value; it does not establish a new, lower
threshold for the BES definition; and it applies requirements where appropriate, i.e.
equipment that carries 75 MVA and is therefore of sufficient size to be relevant to the
reliability of the BES. Aggregator collection systems are designed to employ protection system
equipment at the aggregation node, as well as operational output status monitoring
equipment, and other equipment important to support grid reliability and monitoring at that
aggregation point. Nowhere in the relevant FERC Orders does the language expressly require
the inclusion of individual dispersed generators (PV panels, wind turbines, flywheels,
microturbines, etc.). We believe that deletion of I4 (a) meets the intent of the FERC direction
and properly supports grid reliability. 3. FERC Order 773-A goes on to say in part 60 that,
indeed, dispersed power producers with greater than 75 MVA nameplate capacity are already
registered. For many registered entities across the country, the interpretation has been to
apply the body of NERC standards at the point of aggregation. This regional entity
interpretation of NERC standard applicability at the aggregation point is comparable to the
interpretation described above, and is based on sound reliability thresholds and knowledge of
dispersed power system design. 4. The term "individual resources" utilized in I4 (a) is unclear,
and could refer to the wind plant as a whole. What constitutes an "individual resource?”
More technically precise language should be utilized to specifically identify what resources
are intended to be included per this bullet. 5. In the last two postings, we and other
commenters have asked specific technical questions that have not been answered. Instead,
we have received only a generic reply that the SDT believes our concerns would best be
addressed through clarification of the applicability of individual reliability standards. Please
provide specific replies to the following questions: a. In the August 21, 2013 webinar, the BES
definition drafting team indicated that its justification for the 75 MVA aggregating threshold
in I4 (b) was that 75 MVA is the level that the drafting team believes that single failures
resulting in the loss of generation could have an appreciable impact on the grid. It seems
inconsistent that a 2 MVA individual dispersed generator is deemed significant to reliability
but the equipment that is utilized to connect individual dispersed generators totaling to <75
MVA is deemed not significant to reliability. Please explain the technical rationale for
concluding that an individual dispersed generating asset rated at 2 MVA is important to grid
reliability but that a collector feeder which may impact up to 37 of these individual dispersed
generating assets is not critical to reliability? b. Since the collector feeders are excluded from
the BES definition so that there is not a contiguous BES connection between the individual
dispersed generating asset and the grid, please explain the technical rationale for concluding
that an individual 2 MVA dispersed generator at a facility rated at greater than 75 MVA has
more impact on the BES than does an identical 2 MVA dispersed generator at a facility rated
at less than 75 MVA? If the impact on grid reliability of both units is the same, why is one
considered BES and the other is not? c. In the Consideration of Comments document for the
first draft of the Phase II BES definition, the Drafting Team acknowledged that there are both
existing and pending reliability standards which likely will need to be reviewed and revised to
clarify or correct the applicability of the standard requirements to dispersed generation.
Please identify the reliability gaps being addressed by including individual dispersed
generating assets within the BES definition. In other words, what specific existing or pending
NERC Reliability Standard Requirements are perceived as being needed to be applied to
individual dispersed generating assets to maintain grid reliability? 6. We appreciate that the
SDT acknowledges that numerous existing and pending standards will need to be reviewed
and revised to clarify standard applicability to individual generating units. However, we do
not believe that implementation of the BES definition should go forward until this review and
revision of other standards has been completed. Relative to the approval and implementation
time frames being discussed for the new BES definition, we do not believe any such action
could be taken in a timely enough fashion to resolve industry uncertainty and avoid a major
regulatory burden that would distract from efforts that actually improve grid reliability.
Without that review, there will simply be too much ambiguity in the requirements as they
apply to individual dispersed generating assets and there will be too much compliance effort
spent on trying to apply these ambiguous requirements with no commensurate gain in
reliability. As currently written, the definition will create much regulatory uncertainty in how
auditors will assess an entity's compliance with these ambiguous requirements. Including
individual dispersed generators in the BES definition will cause a major diversion away from
efforts that improve BES reliability, as entities are forced to simultaneously seek relief via the
Exception Process to exclude individual dispersed generators that are insignificant from a
reliability standpoint from their programs while at the same time attempting to modify their
existing compliance programs to accommodate individual dispersed generators in the event
that the exception applications are not approved. With more than 45,000 wind turbines
installed in the U.S. and the vast majority of them in wind plants larger than 75 MVA, NERC
will be faced with a huge backlog of exception requests for small distributed generators while
Generator Owners with dispersed generating assets struggle to implement reliability
standards that were never drafted with the intent of being applicable to anything but large
scale generating stations. As a result, proceeding with the BES definition as currently drafted
would actually impair, rather than improve, bulk electric system reliability. Examples of
standards that were not drafted with small dispersed generators in mind include: • PRC-005-2
Protection System testing – the relay test requirements were developed with large
generators in mind, and differ significantly from requirements in FERC Order 661A, of 2005
that require wind plants to meet Low Voltage Ride-Through (LVRT) and Power Factor Design
Criteria. These standards significantly change the protection scheme applied to individual
turbines, and there is no clarity about how they should be applied. Wind turbine protection
systems are often integral to the wind farm control system and the PRC-005-2 requirements
were developed for protection equipment typically applied to large-scale generation, not
wind farm control systems. • TOP-002 Normal Operations Planning – Under R14 of this
standard, an unplanned outage for any individual wind turbine would require a status
notification report from the GO to the TO/TOP. While such a report can be important for
large central station generation, it would provide no value for a small individual wind turbine
generator. This level of reporting, at typically less than 3 MVA, is much lower that any
practical reliability threshold, and would simply result in a documentation effort with no
value. Similar concerns exist for FAC-008-3, PRC-001-1, PRC-004-2a, PRC-019-1, PRC-024-1,
and PRC-025-1, and other standards in which small-scale dispersed generators were not
considered during the standards’ development. Unless Inclusion I4 (a) is eliminated, or
significantly revised to clarify that the only BES-relevant standards that apply to dispersed
generators are those that affirmatively state that they apply to dispersed generators, we do
not believe implementation of the new BES definition should go forward until all reliability
standards have been reviewed and revised as necessary to clarify the applicability to
individual dispersed generating assets. What reliability benefit is there to a "bright line" BES
definition if there is not a corresponding clarity in the applicability of reliability standards to
the elements deemed to be included in the BES? 7. If the standards drafting team does not
delete I4 (a) as requested above, we ask that I4 (a) be modified to clarify that the only BESrelevant standards that apply to individual dispersed generators are those that affirmatively
state that they apply to dispersed generators. This will help avoid the harmful consequences
of attempting to apply standards that were not written with dispersed generators in mind to
dispersed generators.
Group
DTE Electric
Kathleen Black
No
There is already technical justification to exclude units less than 20MVA, therefore, it is logical
to assume that units smaller than 20 MVA should be excluded. Certainly any collector system
aggregating to less than 20 MVA should also be excluded. The technical justification to
exclude aggregation of less than 75 MVA is the same justification that needs to be applied to
these wind and solar sites. The risk of all the units failing at the same time is very low, unless
it is a common element failure (collector network, control system or transformer). Therefore,
no individual units should be included until they aggregate to 75 MVA. If there is a control
system that can impact 75 MVA, then it is included, but not each generator. 75 MVA
transformers and relaying would be included etc. Even when considering common mode
failure of individual units, it is a very low probability that units would fail at the same time.
No Comment
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
No
The SDT failed to provide technical rationale for their imposing an I4.b sub-aggregate MVA
threshold rather than the point aggregating total capacity within these resources' collectorcircuits, thereby imposing additional compliance burdens upon those asset owners.
Fortunately, a review of the SDT’s recorded deliberations will confirm that they recanted their
earlier draft-2 reliability-based rationale for having done so. AECI acknowledges that, to
some, I4.b might appear more closely aligned with Phase 2’s I2.b BES Scope. However AECI
also believes that the I4.b “from the terminals” debate revealed that I2.b would have been
better technically justifiable at the point of total aggregated plant-capacity as well, a
substantive I2.b refinement seemly outside the scope of this Phase 2 SAR. Yet duplicating a
I2.b technical flaw, under I4.b, technically can neither serve to correct the I2.b flaw nor justify
I4.b.
No
Individual
Spencer Tacke
Modesto Irrigation District
No
Yes
I voted No because I disagree with the criteria proposed for defining the BES. The BES criteria
should be the criteria developed by the WECC BES Definition Task Force in the 2009-2010
time frame, which is based on extensive engineering studies. These extensive studies showed
that system elements with a material impact to the regional interconnected system (i.e., BES
elements), are those elements at which the available short circuit MVA exceeds 6,000 MVA.
This is a very simple criteria based on sound engineering studies, and quite unlike the current
proposed definition of the BES that we are voting on today. Thank you.
Group
PacifiCorp
Ryan Millard
No
PacifiCorp continues to believe that individual dispersed generating units should be excluded
from Inclusion I4 of the revised BES definition. PacifiCorp does not agree with the SDT’s
characterization in the question that no technical rationale was offered by any stakeholder to
support removal of the individual units from Inclusion I4. It is PacifiCorp’s understanding that
at least several commenting entities have provided sound technical arguments to support the
exclusion of individual dispersed generating units. While it may be the case that the SDT does
not believe the technical justifications offered by entities have been compelling, the SDT has
not provided a complete analysis to the industry refuting each of the technical arguments
provided by registered entities. After all, a primary objective of Phase II of the BES definition
project was to carefully consider additional technical arguments that would further refine the
revised definition, including with regard to individual dispersed generating units. PacifiCorp
agrees with the SDT that one suitable solution to address the inclusion of individual dispersed
generating facilities may be via adjustments to individual standards’ applicability sections. In
order to accomplish the recommended case-by-case review, however, a Standard
Authorization Request would likely need to be prepared to commence the NERC standards
development process for each potentially impacted standard. In that case, it is more
appropriate and efficient to exclude such facilities from Inclusion I4 and then initiate changes
to a limited number of impacted standards that should actually apply to individual dispersed
generators, rather than initiate individual projects to modify a larger pool of standards for
which the application to such generators is not appropriate to promote reliability.
No
Individual
Russel Mountjoy
Midwest Reliability Organization
No
In the MRO opinion, the BES definition should not have included individual resources of a
dispersed power producing resource. Instead, the Regions could have opted to include any
that had a material impact to reliability – just the opposite of the way the BES definition was
written. NERC talks of a guidance document in order to define those resources which are a
part of the BES. This does not bear much weight when put towards a FERC approved
definition and FERC approved Reliability Standards. The notion to use the BES implementation
period of two years to work with the Standards Committee in order to revise the standards
identified as requiring revisions doesn’t seem workable. The implementation period is the
time that has been identified for Registered Entities to bring their programs into compliance,
it is not reasonable to expect the entities to expend their resources to bring their programs
up to date with the possibility of the standards not being applicable. Nor is it reasonable to
expect entities to postpone implementing programs in anticipation of standards being revised
prior to the end of the implementation period.
No
Individual
Ryan Walter
Tri-State Generation and Transmission Association, Inc.
No
Tri-State disagrees that FERC Orders 773 and 773-A approved the inclusion of individual
dispersed generating units that are individually, or in aggregate, below the capacity that
requires the owner to register as a Generator Owner. Inclusion I4 of the current draft of the
BES definition does require that under various scenarios. It is apparent from the comments to
draft 2 of the Definition, and the questions during the webinar that was held by the drafting
team, that Inclusion I4a) is disputed by a large percentage of registered entities and there is
no technical basis for its inclusion in the definition. When asked during the webinar whether
the drafting team had approached FERC regarding whether all individual dispersed units were
to be included and about the fact that there was no technical justification for such inclusion,
the drafting team simply stated that the FERC staff do not speak for the Commission. While it
is be true that the staff do not speak for the Commission, all the drafting teams have FERC
staff available that are able to convey the thoughts of the drafting teams and industry to the
Commission. Tri-State agrees that the collection system for dispersed generation that
aggregates to 75 MVA or more is important to include in the definition, since a single
contingency could lead to loss of a large magnitude of generation. But loss of an individual
small generator, oftentimes 2 MVA or less, has no direct consequence to the reliability of the
BES.
No
Group
Bonneville Power Administration
Jamison Dye
Yes
No
Individual
Mary Lou Ideus
EDP Renewables North America LLC
AWEA
No
EDP Renewables North America LLC (EDPR NA) disagrees with the inclusion of individual
dispersed power producing units (individual wind turbines and solar units (inverters)) in the
definition of I4. Individual wind turbines have negligible or no effect on the reliability of the
BES due to their generating capacity and the fact that they are intermittent resources.
Inclusion of individual wind turbines would require a wind generator to consider each wind
turbine in its compliance program for Standards such as PRC-005. Since there is no discrete
equipment, outside of the turbine control system, in a wind turbine that could logically be
included in a wind generator’s Protection System devices to be tested and maintained, the
wind generator would be forced to seek exclusion under the Applicability section of other
affected Standards. This would impose an administrative burden not only on the wind
generation companies but also on each of the NERC Regional Entities, and indeed NERC itself,
to consider each of the affected Registered Entity’s request for exclusion from Applicability
with certain of the currently enforceable Standards. In addition, inclusion of individual wind
turbines in I4 would require revisions to each of the applicable Reliability Standards, a lengthy
process. Compliance with many standards including the following would be required for such
low level BES elements: FAC-003, PRC-001, PRC-004, PRC-005, and VAR-002. The SDT is asking
for technical reasons for disagreement with the language; however, EDPR NA believes that
the SDT has not provided sound technical reasons for inclusion of individual dispersed power
producing units in I4. Suggested language change: I4: The point at which the aggregation
equals to a capacity threshold of 75 MVA or above.
Additional comments received from PSEG (voting entities are in NPCC and RFC, and are in these
segments: 1, 3, 5, & 6):
1. The SDT has re-structured the language of Inclusion I4 to more clearly reflect the SDT’s
intent to include individual dispersed power producing units (such as wind and solar units)
that aggregate to greater than 75 MVA , along with the collector system that connects these
units, from the point they aggregate to greater than 75 MVA to the point of connection at
100kV or higher. While the SDT recognizes that some stakeholders do not agree with the
inclusion of individual dispersed power producing units, FERC Orders 773 and 773-A
approved the inclusion of these individual units. No stakeholder has provided a technical
rationale to support removal of the individual units from the definition. The SDT believes
that stakeholder concerns about inclusion of individual units may be addressed by
specifying the Facilities to which an individual standard applies within the Applicability
section of that standard.
With this background, can you support the proposed clarifications to I4? If not, please
provide technical rationale for your disagreement along with suggested language changes.
Yes:
No: X
Comments: As we stated in our comments to the prior posting, we believe exclusion of
“collector systems” for dispersed I4 generators, which includes their GSU, from the BES
while similar collector systems are included in the BES for I2 generators creates an unlevel
competitive environment between I2 and I4 generators. Dispersed generators are a
significant and growing part of generation resources and they compete with traditional
generation. Other than the fact that FERC allowed the collector system exclusion, the
drafting team has offered no reliability rationale for excluding the collector systems of
dispersed generators while including them for I2 generators. [In Order 773, although FERC
(P 113 and P 114) stated that radial collector systems used solely to aggregate generation
SHOULD be part of the BES since multiple transformers connections did not exempt I2
generators; however, they did not direct NERC to include the collector system in I4
generators in the BES.]
Because of the disparate treatment of collector systems, we believe that the drafting team’s
BES definition violates Section 303 – Relationship between Reliability Standards and
Competition – in the NERC Rules of Procedure under Paragraph 1. Paragraph 1 in Section
303 states: “Competition — A Reliability Standard shall not give any market participant an
unfair competitive advantage.” Furthermore, the exclusion of the collector system for I4
generators is the only incident of a non-contiguous BES in the BES definition. The collector
systems are solely used by I4 generators to aggregate generation; they have no local
distribution application and therefore to do come under the local distribution exemption in
the core BES definition (i.e., the BES definition “does not include facilities used in the local
distribution of electric energy”).
Consideration of Comments
Project 2010-17 Proposed Definition of Bulk Electric System Phase 2
The Project 2010-17 Drafting Team thanks all commenters who submitted comments on the standard.
These standards were posted for a 30-day public comment period from September 27, 2013 through
October 29, 2013. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 40 sets of comments, including
comments from approximately 98 different people from approximately 66 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 standard’s project page.
The SDT did not receive any technically supported arguments to support making any changes to the
posted definition.
The SDT will be revising the Reference Document once the Phase 2 project is completed and will post it
for comments as was done with the Phase 1 version. Comments on specific sections and diagrams will
be considered at that time.
Minority opinion:
The SDT has retained the language of Inclusion I4 to clearly reflect the SDT’s intent to include individual
dispersed power producing units (such as wind and solar units) that aggregate to greater than 75 MVA,
along with the collector system that connects these units, from the point they aggregate to greater
than 75 MVA to the point of connection at 100kV or higher. While the SDT recognizes that some
stakeholders do not agree with the inclusion of individual dispersed power producing units, FERC
Orders 773 and 773-A approved the inclusion of these individual units. Technical rationale to support
removal of the individual units from the definition was not seen in the stakeholder comments received
by the SDT. The SDT believes that stakeholder concerns about inclusion of individual units may be
addressed by specifying the Facilities to which an individual standard applies within the Applicability
section of that standard.
In the Phase 2 definition, the drafting team has modified the treatment of collector systems for dispersed power
producing resources. FERC Orders 773 and 773-A identified a concern that the Commission expressed regarding
dispersed power collector systems. This has prompted the SDT to consider an appropriate and consistent
method of addressing collector systems. The result addresses collector systems in a clear fashion that leaves no
room for arbitrary determinations and eliminates the unintended consequences of categorically including as part
of the BES assets that may include local distribution facilities.
Rationale:
The significant differences in collector system configurations that exist today did not lend itself to a continentwide bright-line determination which has resulted in the SDT’s effort to properly identify the portions of the
collector system which consistently provides a reliability benefit to the interconnected transmission network and
are easily identified within collector systems. The result identifies the point of aggregation of 75 MVA and above
and the interconnecting facilities to the interconnected transmission network. The aggregation threshold is
consistent with the aggregation of capacity in Inclusion I4 and recognizes that the loss of those facilities would
represent a loss of 75 MVA capacity to the BES.
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
Index to Questions, Comments, and Responses
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments: Project 2010-17 October 2013
2
1.
2.
The SDT has re-structured the language of Inclusion I4 to more clearly reflect the SDT’s
intent to include individual dispersed power producing units (such as wind and solar units)
that aggregate to greater than 75 MVA , along with the collector system that connects
these units, from the point they aggregate to greater than 75 MVA to the point of
connection at 100kV or higher. While the SDT recognizes that some stakeholders do not
agree with the inclusion of individual dispersed power producing units, FERC Orders 773
and 773-A approved the inclusion of these individual units. No stakeholder has provided
a technical rationale to support removal of the individual units from the definition. The
SDT believes that stakeholder concerns about inclusion of individual units may be
addressed by specifying the Facilities to which an individual standard applies within the
Applicability section of that standard. With this background, can you support the
proposed clarifications to I4? If not, please provide technical rationale for your
disagreement along with suggested language changes. .................................... …………………10
Are there any other concerns with this definition that haven’t been covered in previous
postings, questions and comments? ...............................................................................37
Consideration of Comments: Project 2010-17 October 2013
3
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
Guy Zito
Additional Organization
Northeast Power Coordinating Council
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC
10
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
10
6.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
7.
Kathleen Goodman
ISO - New England
NPCC
2
8.
Michael Jones
National Grid
NPCC
1
9.
Mark Kenny
Northeast Utilities
NPCC
1
10. Christina Koncz
PSEG Power LLC
NPCC
5
11. Helen Lainis
Independent Electricity System Operator
NPCC
2
NPCC
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
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 Energyt, 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. David Burke
Orange and Rockland Utilities Inc.
NPCC
3
21. Ayesha Sabouba
Hydro One Networks Inc.
NPCC
1
22. Brian Shanahan
National Grid
NPCC
1
23. Wayne Sipperly
Ne York Power Authority
NPCC
5
24. Ben Wu
Orange and Rockland Utilities Inc.
NPCC
1
2.
Group
2
3
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
X
X
Scott Brame
North Carolina Electric Membership
Corporation
X
X
4
5
X
6
7
X
None
3.
Group
Additional Member
Additional Organization
North Carolina Electric Membership Corporation SERC
5
2. John Lemire
North Carolina Electric Membership Corporation SERC
4
3. Doug White
North Carolina Electric Membership Corporation SERC
3
4. Robert Thompson
North Carolina Electric Membership Corporation SERC
1
Group
Ben Engelby
Additional Member
ACES Standards Collaborators
Additional Organization
X
Region Segment Selection
1. John Shaver
Arizona Electric Power Cooperative/Southwest Transmission Cooperative, Inc. WECC 1, 4, 5
2. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
3. Shari Heino
Brazos Electric Power Cooperative, Inc.
SERC
1, 5
4. Kevin Lyons
Central Iowa Power Cooperative
MRO
5. Mohan Sachdeva
Buckeye Power, Inc.
RFC
5.
Group
Robert Rhodes
Additional Member
1.
John Allen
Additional Organization
City Utilities of Springfield
X
Region Segment Selection
1. Scott Brame
4.
X
SPP Standards Review Group
3, 4
X
Region Segment Selection
SPP
1, 4
Consideration of Comments: Project 2010-17 October 2013
5
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2.
Brenda Frazer
Edison Mission Marketing and Trading SPP
5, 6
3.
James Nail
City of Independence, MO
SPP
3
4.
David Pham
Empire District Electric
SPP
1
5.
Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5
6.
Don Schmit
Nebraska Public Power District
MRO
1, 3, 5
7.
Kayleigh Wilkerson
Lincoln Electric System
MRO
1, 3, 5
8.
Laura Cox
Westar Energy
SPP
1,3,5,6
9.
Kevin Nincehesler
Westar Energy
SPP
1,3,5,6
Westar Energy
SPP
1,3,5,6
10. Don Taylor
6.
Group
Wayne Johnson
Southern Company: Southern Company
Services, Inc.; Alabama Power Company;
Georgia
Group
Louis Slade
Dominion
2
3
4
5
6
X
X
X
X
X
X
X
X
7
None
7.
Additional Member Additional Organization Region Segment Selection
1. Mike Garton
Dominion
NPCC
5, 6
2. Randi Heise
Dominion
MRO
6
3. Michael Crowley
Dominion
SERC
1, 3, 5, 6
4. Connie Lowe
Dominion
RFC
5, 6
8.
Group
Brent Ingebrigtson
Additional Member
Additional Organization
PPL NERC Registered Affiliates
Region Segment Selection
1.
Brenda Truhe
PPL Electric Utilities Corporation RFC
1
2.
Annette Bannon
PPL Generation, LLC
RFC
5
PPL Montana, LLC
WECC 5
PPL Susquehanna, LLC
RFC
5
PPL EnergyPlus, LLC
MRO
6
6.
NPCC
6
7.
RFC
6
8.
SERC
6
9.
SPP
6
10.
WECC 6
3.
4.
5.
9.
Elizabeth Davis
Group
Michael Lowman
Duke Energy
Consideration of Comments: Project 2010-17 October 2013
X
X
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
10.
Group
Kathleen Black
Additional Member
Additional Organization
DTE Electric
NERC Compliance
RFC
3
2. Daniel Herring
NERC Training & Standards Development RFC
4
3. Mark Stefaniak
Regulated Marketing
5
RFC
11.
Associated Electric Cooperative, Inc. JRO00088
David Dockery
Additional Member
X
X
X
X
X
X
X
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
12.
X
Region Segment Selection
1. Kent Kujala
Group
X
Group
Ryan Millard
PacifiCorp
Group
Jamison Dye
Bonneville Power Administration
None
13.
Additional Member
Additional Organization
Transmission Reliability Program WECC 1
2. Kelly Johnson
Customer Service Engineering
WECC 1
3. John Anasis
Technical Operations
WECC 1
15.
X
X
Region Segment Selection
1. Lorissa Jones
14.
X
Individual
Bangalore
Vijayraghavan
Pacific Gas and Electric Comapny
Individual
John Falsey
Invenergy LLC
X
16.
Individual
Thomas Foltz
American Electric Power
X
17.
Individual
David Jendras
Ameren
X
Consideration of Comments: Project 2010-17 October 2013
X
X
X
X
X
X
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
18.
Individual
2
X
3
4
X
5
X
6
NIPSCO
Individual
20. Individual
Kathleen Goodman
Russell A Noble
ISO New England, Inc.
Cowlitz PUD
21.
Individual
Kenneth A Goldsmith
Alliant Energy
22.
Individual
Gerald G Farringer
Consumers Energy
23.
Individual
Joseph G DePoorter
Madison Gas and Electric Company
24.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
25.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
X
26.
Individual
Marie Knox
MISO
27.
Individual
Alice Ireland
Xcel Energy
28.
Individual
Thomas Breene
WPSC
29.
Individual
Patrick Farrell
Southern California Edison Company
30.
Individual
Thomas Gianneschi
Alcoa, Inc.
31.
Individual
Gary Kruempel
MidAmerican Energy Company
X
32.
Individual
Randi Nyholm
Minnesota Power
X
33.
Individual
Don Streebel
Idaho Power Co.
X
34.
Individual
Barbara Kedrowski
Wisconsin Electric Power Company
35.
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
Individual
37. Individual
Michael Goggin
Spencer Tacke
American Wind Energy Association
Modesto Irrigation District
38.
Russel Mountjoy
36.
Individual
Individual
Ryan Walter
Midwest Reliability Organization
Tri-State Generation and Transmission
Association, Inc.
Individual
Mary Lou Ideus
EDP Renewables North America LLC
39.
40.
Consideration of Comments: Project 2010-17 October 2013
8
9
10
X
Joe O'Brien
19.
7
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
X
X
8
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).
Summary Consideration: The SDT thanks you for your comments.
Organization
Agree
Invenergy LLC
EDP Renewables North America LLC
MISO
Agree
Agree
Consideration of Comments: Project 2010-17 October 2013
Supporting Comments of “Entity Name”
AWEA
AWEA
Madison Gas & Electric
9
1. The SDT has re-structured the language of Inclusion I4 to more clearly reflect the SDT’s intent to include individual dispersed
power producing units (such as wind and solar units) that aggregate to greater than 75 MVA , along with the collector system that
connects these units, from the point they aggregate to greater than 75 MVA to the point of connection at 100kV or higher. While
the SDT recognizes that some stakeholders do not agree with the inclusion of individual dispersed power producing units, FERC
Orders 773 and 773-A approved the inclusion of these individual units. No stakeholder has provided a technical rationale to
support removal of the individual units from the definition. The SDT believes that stakeholder concerns about inclusion of
individual units may be addressed by specifying the Facilities to which an individual standard applies within the Applicability
section of that standard.
With this background, can you support the proposed clarifications to I4? If not, please provide technical rationale for your
disagreement along with suggested language changes.
Summary Consideration: The SDT has retained the language of Inclusion I4 to clearly reflect the SDT’s intent to include individual
dispersed power producing units (such as wind and solar units) that aggregate to greater than 75 MVA, along with the collector system
that connects these units, from the point they aggregate to greater than 75 MVA to the point of connection at 100kV or higher. While
Technical rationale to support removal of the individual units from the definition was not seen in the stakeholder comments received by
the SDT. The SDT recognizes that some stakeholders do not agree with the inclusion of individual dispersed power producing units,
FERC Orders 773 and 773-A approved the inclusion of these individual units. No stakeholder has provided a technical rationale to
support removal of the individual units from the definition. The SDT believes that stakeholder concerns about inclusion of individual
units may be addressed by specifying the Facilities to which an individual standard applies within the Applicability section of that
standard.
Organization
Northeast Power Coordinating Council
Yes or No
Question 1 Comment
No
The use of the word “capacity” is a concern. Generators might not be
considered BES under the definition. Suggested change to I4 as
follows: I4 - Dispersed power producing resources that aggregate to a
gross total nameplate rating greater than 75 MVA, and that are
connected through a system designed primarily for delivering such
energy to a common point of connection at a voltage of 100 kV or
above. Thus, the facilities designated as BES are: a) The individual
resources, and b) The system designed primarily for delivering energy
Consideration of Comments: Project 2010-17 October 2013
10
Organization
Yes or No
Question 1 Comment
from the point where those resources aggregate to greater than 75
MVA to a common point of connection at a voltage of 100 kV or
above.
ISO New England, Inc.
No
The use of the word “capacity” is a concern. Below is suggested
language.I4 - Dispersed power producing resources that aggregate to
a total gross nameplate rating greater than 75 MVA, and that are
connected through a system designed primarily for delivering such
energy to a common point of connection at a voltage of 100 kV or
above. Thus, the facilities designated as BES are: a) The individual
resources, and b) The system designed primarily for delivering energy
from the point where those resources aggregate to greater than 75
MVA to a common point of connection at a voltage of 100 kV or
above.
Response: The SDT does not believe that the use of the term ‘capacity’ is a concern or that it will cause generators not to be
considered under the definition. Based on comments received, the majority of the industry seems to understand the use of the
term. No change made.
Arizona Public Service Company
No
The definition should not apply to individual dispersed units that are
less than 5 MW because independent units less than 5 MW are too
small to have an impact on the BES.
Response: The definition only applies to individual units when they are part of an aggregation that is greater than 75 MVA. Individual
stand-alone units of 5 MW would not be included in the definition. No change made.
North Carolina Electric Membership
Corporation
No
Consideration of Comments: Project 2010-17 October 2013
We have voted affirmative for this project in the past but are now
changing our vote to negative based on the changes made to I4.We
feel that the drafting team has further complicated the BES definition
by the proposed language in Inclusion I4. According to the Phase 1
definition, dispersed power producing units would only be included if
11
Organization
Yes or No
Question 1 Comment
the units reached the 75 MVA aggregate threshold. There is nothing in
the Phase 1 definition that would include collector system equipment.
The Phase 2 definition is problematic because there is uncertainty
regarding the scope of equipment that that would be included as a
portion of the collector system. This ambiguity has raised concerns
that regional compliance staff may ultimately determine a different
set of equipment is included in the BES than the registered entity will
leaving the burden on the registered entity to argue why certain
elements should not be included in the BES. This will lead to
inconsistent compliance outcomes. We cannot support a definition
with vague and ambiguous language that could result in negative
compliance implications during registration, audits, and enforcement
processes. Furthermore, we do not believe any part of the collector
system should be included in the definition.
ACES Standards Collaborators
No
Consideration of Comments: Project 2010-17 October 2013
We feel that the drafting team has further complicated the BES
definition by the proposed language in Inclusion I4. According to the
Phase 1 definition, dispersed power producing units would only be
included if the units reached the 75 MVA aggregate threshold. There
is nothing in the Phase 1 definition that would include collector
system equipment. The Phase 2 definition is problematic because
there is uncertainty regarding the scope of equipment that that would
be included as a portion of the collector system. This ambiguity has
raised concerns that regional compliance staff may ultimately
determine a different set of equipment is included in the BES than the
registered entity will leaving the burden on the registered entity to
argue why certain elements should not be included in the BES. This
will lead to inconsistent compliance outcomes. We cannot support a
definition with vague and ambiguous language that could result in
negative compliance implications during registration, audits, and
enforcement processes. Furthermore, we do not believe any part of
12
Organization
Yes or No
Question 1 Comment
the collector system should be included in the definition.
Response: FERC Orders 773 and 773-A requested the SDT to consider collector systems as part of Phase 2. The SDT has addressed
those collector systems in a clear fashion that leaves no room for arbitrary determinations. Furthermore, no change has been made
to the definition as to the inclusion of individual units in Phase 2 – units are still only included if they aggregate to greater than 75
MVA. No change made.
SPP Standards Review Group
No
While we understand that FERC has basically directed the drafting
team to include individual dispersed power producing units in the BES,
we are concerned about the need for coordination between drafting
teams for other reliability standards, such as PRC-004, PRC-005, FAC008, etc, which may be impacted by the inclusion of these generating
units into the BES. Have steps been taken to ensure that this
coordination has taken place?
Response: The SDT did review existing standards and believes that no changes are necessary due to the revised definition.
Southern Company: Southern Company
Services, Inc.; Alabama Power
Company; Georgia
No
Eliminate Inclusion I4.a. If an individual generating element of a
dispersed power producing facility is 20 MVA or larger at a facility
rated at 75 MVA or larger it should be included.
At Inclusion I4.b, Southern disagrees with the premise that BES
elements (measured for compliance) should be applied to the
individual dispersed power elements. We do not see the reliability
benefit of tracking all of the compliance elements for individual wind
turbines when the focus should be placed on the aggregate of the
facilities. The proposed approach is similar to applying NERC
requirements to the individual coils of a large generator. The subject
inclusion should limit the applicability of the BES to the collector bus
and the capacity at this point should be 75 MVA or greater to qualify
as a BES element.
Consideration of Comments: Project 2010-17 October 2013
13
Organization
Yes or No
Question 1 Comment
Response: Individual units that aggregate to greater than 75 MVA were included in the prior definition and have been accepted by
FERC as part of the BES. Nothing changed in that regard in Phase 2 and no entity has provided technical justification for deleting
these units. FERC Orders 773 and 773-A requested the SDT to consider collector systems as part of the definition. No change made.
DTE Electric
No
There is already technical justification to exclude units less than
20MVA, therefore, it is logical to assume that units smaller than 20
MVA should be excluded. Certainly any collector system aggregating
to less than 20 MVA should also be excluded. The technical
justification to exclude aggregation of less than 75 MVA is the same
justification that needs to be applied to these wind and solar sites.
The risk of all the units failing at the same time is very low, unless it is
a common element failure (collector network, control system or
transformer). Therefore, no individual units should be included until
they aggregate to 75 MVA. If there is a control system that can impact
75 MVA, then it is included, but not each generator. 75 MVA
transformers and relaying would be included etc. Even when
considering common mode failure of individual units, it is a very low
probability that units would fail at the same time.
Response: The SDT is not aware of any technical justification for excluding units less than 20 MVA nor has any been submitted. No
individual units are included unless they are greater than 20 MVA or aggregate to greater than 75 MVA. No change made.
Associated Electric Cooperative, Inc. JRO00088
No
Consideration of Comments: Project 2010-17 October 2013
The SDT failed to provide technical rationale for their imposing an I4.b
sub-aggregate MVA threshold rather than the point aggregating total
capacity within these resources' collector-circuits, thereby imposing
additional compliance burdens upon those asset owners. Fortunately,
a review of the SDT’s recorded deliberations will confirm that they
recanted their earlier draft-2 reliability-based rationale for having
done so. AECI acknowledges that, to some, I4.b might appear more
closely aligned with Phase 2’s I2.b BES Scope. However AECI also
14
Organization
Yes or No
Question 1 Comment
believes that the I4.b “from the terminals” debate revealed that I2.b
would have been better technically justifiable at the point of total
aggregated plant-capacity as well, a substantive I2.b refinement
seemly outside the scope of this Phase 2 SAR. Yet duplicating a I2.b
technical flaw, under I4.b, technically can neither serve to correct the
I2.b flaw nor justify I4.b.
Response: Collector systems in Inclusion I4b are treated comparably to those in Inclusion I2b. The 75 MVA threshold was validated
in the NERC Planning Committee Report of March 2013 which can be found at:
http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fin
al_20130306.pdf No change made.
PacifiCorp
No
PacifiCorp continues to believe that individual dispersed generating
units should be excluded from Inclusion I4 of the revised BES
definition. PacifiCorp does not agree with the SDT’s characterization in
the question that no technical rationale was offered by any
stakeholder to support removal of the individual units from Inclusion
I4. It is PacifiCorp’s understanding that at least several commenting
entities have provided sound technical arguments to support the
exclusion of individual dispersed generating units. While it may be the
case that the SDT does not believe the technical justifications offered
by entities have been compelling, the SDT has not provided a
complete analysis to the industry refuting each of the technical
arguments provided by registered entities. After all, a primary
objective of Phase II of the BES definition project was to carefully
consider additional technical arguments that would further refine the
revised definition, including with regard to individual dispersed
generating units.
PacifiCorp agrees with the SDT that one suitable solution to address
the inclusion of individual dispersed generating facilities may be via
Consideration of Comments: Project 2010-17 October 2013
15
Organization
Yes or No
Question 1 Comment
adjustments to individual standards’ applicability sections. In order to
accomplish the recommended case-by-case review, however, a
Standard Authorization Request would likely need to be prepared to
commence the NERC standards development process for each
potentially impacted standard. In that case, it is more appropriate and
efficient to exclude such facilities from Inclusion I4 and then initiate
changes to a limited number of impacted standards that should
actually apply to individual dispersed generators, rather than initiate
individual projects to modify a larger pool of standards for which the
application to such generators is not appropriate to promote
reliability.
WPSC
No
Consideration of Comments: Project 2010-17 October 2013
As our previous comments have indicated, we agree with including
the Generating stations with dispersed generation from the point of
aggregation to 75 MVA as I4-b does. We also agree with the
statement made on the BES Phase II webinar of August 21 that this is
the point where the dispersed power plant is significant to the
reliability of the BES. We continue to disagree with including the
individual resources themselves since, as indicated on the previously
referenced webinar, they are not significant to the reliability of the
BES. The technical rationale for not including dispersed power
producing resources has been included in many past comments and
will not be restated here. Compliance with most protection system
and equipment rating standards is not possible for individual BES wind
turbines without revisions to the standards, or at best without
significant resources to apply existing standards to individual units.
Some of the standards effected include PRC-004-2a, FAC-001, FAC003, FAC-008-3, MOD-024, MOD-025, MOD-026, MOD-027, PRC-005,
PRC-006-SPP-01, PRC-019, PRC-024, PRC-025, and TOP-003.But we
continue to stress that including an I4a will require significant
resources in personnel and modifications or result in fast-tracking
16
Organization
Yes or No
Question 1 Comment
Standard changes to make compliance possible with no improvement
in reliability of the BES. These resources would be better utilized
elsewhere to actually improve reliability.
MidAmerican Energy Company
No
Consideration of Comments: Project 2010-17 October 2013
MidAmerican continues to believe that individual dispersed
generating units should be excluded from Inclusion I4 of the revised
BES definition. MidAmerican does not agree with the SDT’s
characterization in the question that no technical rationale was
offered by any stakeholder to support removal of the individual units
from Inclusion I4. It is MidAmerican’s understanding that at least
several commenting entities have provided sound technical
arguments to support the exclusion of individual dispersed generating
units. While it may be the case that the SDT does not believe the
technical justifications offered by entities have been compelling, the
SDT has not provided a complete analysis to the industry refuting each
of the technical arguments provided by registered entities. After all, a
primary objective of Phase II of the BES definition project was to
carefully consider additional technical arguments that would further
refine the revised definition, including with regard to individual
dispersed generating units. MidAmerican agrees with the SDT that one
suitable solution to address the inclusion of individual dispersed
generating facilities may be via adjustments to individual standards’
applicability sections. For example, Reliability Standard MOD-025-2
(pending approval at FERC) includes a provision addressing real power
testing for variable generating facilities. In order to accomplish the
recommended case-by-case review, however, a Standard
Authorization Request would likely need to be prepared to commence
the NERC standards development process for each potentially
impacted standard. In that case, it is more appropriate and efficient
to exclude such facilities from Inclusion I4 and then initiate changes to
a limited number of impacted standards that should actually apply to
17
Organization
Yes or No
Question 1 Comment
individual dispersed generators, rather than initiate individual projects
to modify a larger pool of standards for which the application to such
generators is not appropriate to promote reliability.
Wisconsin Electric Power Company
No
Wind generators and solar panels are intermittent resources that are
not as dependable as other sources for supporting grid reliability. A
sudden drop in wind speed or solar intensity will instantaneously
reduce the MW output of all the individual wind turbines or solar
panels in the area. It follows then that a single wind turbine or solar
panel could not be an Element or Facility necessary for the reliable
operation and planning of the interconnected bulk power system.
However, common mode failure of multiple turbines or solar panels
could be significant to the reliability and planning of the BES. Efforts
should be focused on preventing / mitigating the loss of multiple
generators with an aggregated capacity of greater than 75MVA.
Therefore the elements necessary for the reliable operation and
planning of the interconnected bulk power system are the devices
that are located where the power is aggregated, and not the individual
generators. If individual small generators that are a part of an
aggregated facility of 75 MVA or larger (e.g. a 75 MVA wind or solar
farm) are considered a part of the BES due to that aggregation, the
NERC Standard requirements should only be applied to the
aggregation (e.g. the interconnection with the transmission system)
and should not be applied to individual generators of less than 20
MVA. This would be consistent with the NERC registration criteria for
single and multiple generators at a site.
Response: FERC Orders 773 and 773-A accepted the individual units as part of the BES when they aggregate to greater than 75 MVA.
The SDT is not aware of any technical justifications that have been provided showing why or how these units should not be part of
the BES. No change made.
Consideration of Comments: Project 2010-17 October 2013
18
Organization
Yes or No
Question 1 Comment
A SAR has been submitted to the NERC Standards Committee to address the applicability of small, dispersed generating resources
within the body of the existing standards. (See:
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_20131017a_agenda_package.pdf - item 5.) Deleting
those units from the definition at this time could cause a reliability gap. The proper procedure is to continue to include these units in
the BES and allow the project initiated by the SAR to determine when such units can be safely removed from specific standard
applicability. No change made.
Cowlitz PUD
No
We understand the difficulty of backtracking on past progress. We
have voted in the affirmative for the greater objective of not impeding
the overall positive progress of the definition. However, we
acknowledge the industry has identified a valid concern over I4, and
although the SDT is powerless to correct the issue, it is important to
record and document reservations so future efforts in standard
development may be facilitated to correct problems with compliance
overreach. Most of the I4 facilities that will be included into the BES
inherently work against reliability, and this characteristic can’t be
mitigated by adherence to the current GO/GOP standards in place.
For example, assuring an individual generator protection system of a
wind/solar unit will not misoperate adds little protection to the BES
when the unit is frequently down due to insufficient wind or sunshine.
It is a fact that such generation can’t be designated as must run, and
instead other generation units which can be dispatched must be
available on demand to replace lost wind/solar resources. Therefore,
we admonish FERC and NERC to recognize the true nature of wind and
solar resources as an effort to reduce carbon footprint on the
environment and are not intended to replace dispatchable generation,
and that compliance without any reliability return should be removed
to facilitate its development.
Response: The SDT thanks you for your support and understanding.
Consideration of Comments: Project 2010-17 October 2013
19
Organization
Consumers Energy
Yes or No
Question 1 Comment
No
The inclusion and the clarification of the inclusion seem to contradict
each other. The highlight portion above seems to indicate inclusion
only from the point of aggregation of 75MVA or above. This, in most
Wind Park cases would include a collector bus but probably not
individual wind turbines. However I4 seems to indicate that the case
of a Wind Park that has a total aggregation of 75 MVA, all associated
equipment including every individual wild turbine would be included.
There is inconsistency. Technical justification should be needed to
include resources in the BES, not the other way around. Is there a real
expectation that a single collector circuit containing ten, 1.2MW wind
turbines can cause cascading or uncontrollable outages of the
surrounding system? It is extremely doubtful. Consumers Energy
supports the inclusion of equipment where the aggregation of 75 MVA
or more connects to the Bulk Electric System at voltages of 100kv or
greater. There is a clear indication here that a single contingency can
remove the total of the capacity from the system where with the
proposed inclusion does not. Administrative burden and compliance
risk must be weighed against reliability gain. Including individual wind
turbines rather than the aggregate of the wind farm increases such
burden without any reliability gain.
Response: A single collector circuit of ten 1.2 MW wind turbines is not included in the BES by application of the definition. Only when
the generation aggregates to greater than 75 MVA are the units and the collector system part of the BES as was shown in the diagram
presented at the SDT webinar
http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Elec1/bes_phase2_third_posting_20
131010_webinar_final.pdf . The SDT believes that the language clarification and re-structuring that were made for this posting clearly
show that. Furthermore, if necessary, as approved by FERC in Orders 773 and 773-A, the exception process provides a way to add
Elements to, or remove Elements from, the Bulk Electric System. No change made.
Madison Gas and Electric Company
No
Consideration of Comments: Project 2010-17 October 2013
MGE does not understand why individual dispersed power resources
remain to be include as we clearly stated during the last comment
20
Organization
Yes or No
Question 1 Comment
period. The SDT has stated that no technical rational to support there
removal. FAC-001 and FAC-002 are mandatory enforceable Standards
that entity's must follow. These Standards provide the justification as
pointed out in our last set of comments. The SDT has stated in order
to fix this, an addition SAR would be submitted (such as the GOTO) to
"fix" this issue. Why would the ERO what to expend resources to fix
something after the fact when the SDT has the ability to fix it now.
The removal of I4a will solve this issue. If individual resources need to
be in based on system instability issues, then this can be addressed at
a later date, once it is proven that individual resources need to be
considered part of the BES and the individual resources cause BES
instability.
Response: Individual dispersed power producing resources are only included in the definition if they are part of an aggregation of
greater than 75 MVA. This fact did not change due to the revised definition. FERC has already accepted this status in Orders 773 and
773-A. The SDT does not believe that FAC-001 and FAC-002 present technical justification for excluding such resources. No change
made.
Xcel Energy
No
Consideration of Comments: Project 2010-17 October 2013
In several prior comment periods, we have asked many technical
questions of the BES SDT, and continue to get generic non-substantive
replies. While a majority of our questions still remain unanswered, we
have elected to not submit them again. However, we believe it is
especially important to understand the SDT’s response to this
question. When considering a wind farm that would qualify as BES
under the currently drafted version, it seems inconsistent that a 2
MVA individual dispersed generator is deemed significant to reliability,
while the equipment that is utilized to connect a sub-set of the
individual dispersed generators totaling to <75 MVA is deemed not
significant to reliability. Please explain the technical rationale for
concluding that an individual dispersed generating asset rated at 2
MVA is important to grid reliability but that a collector feeder for a
21
Organization
Yes or No
Question 1 Comment
sub-set of these generators which may impact up to 35 (70 MVA) of
these individual dispersed generating assets is not critical to
reliability?
Minnesota Power
No
Minnesota Power does not believe that 2 MW generators, whether or
not they aggregate to 75 MW, should be included in the definition of
Bulk Electric System when the distribution transformers that control
multiple units are not included. Furthermore, a non-contiguous Bulk
Electric System is problematic for maintaining reliability.
Seminole Electric Cooperative, Inc.
No
The drafting team has proposed revised changes to a requirement
concerning distributed generation. In particular, when distributed
generation, e.g., wind turbines, accumulate to more than 75 MVA,
only the turbines and the equipment collecting/transferring more
than 75 MVA is covered as BES equipment. This allows for scenarios
where non-BES equipment might be located between two separate
groups of BES equipment. Seminole does not believe this is FERC’s
intent. Seminole acknowledges that FERC did not specifically address
distributed generation in past orders when attempting to correct the
BES language that resulted in having non-BES equipment separate
groups of BES equipment. However, Seminole does not believe the
drafting team’s reasoning is sufficient for this exception. Seminole
believes that all of the equipment in this scenario should be either
BES-regulated or non-BES (non-NERC) regulated.
PSE&G
No
As we stated in our comments to the prior posting, we believe
exclusion of “collector systems” for dispersed I4 generators, which
includes their GSU, from the BES while similar collector systems are
included in the BES for I2 generators creates an unlevel competitive
environment between I2 and I4 generators. Dispersed generators are
a significant and growing part of generation resources and they
Consideration of Comments: Project 2010-17 October 2013
22
Organization
Yes or No
Question 1 Comment
compete with traditional generation. Other than the fact that FERC
allowed the collector system exclusion, the drafting team has offered
no reliability rationale for excluding the collector systems of dispersed
generators while including them for I2 generators. [In Order 773,
although FERC (P 113 and P 114) stated that radial collector systems
used solely to aggregate generation SHOULD be part of the BES since
multiple transformers connections did not exempt I2 generators;
however, they did not direct NERC to include the collector system in I4
generators in the BES.]
Because of the disparate treatment of collector systems, we believe
that the drafting team’s BES definition violates Section 303 –
Relationship between Reliability Standards and Competition – in the
NERC Rules of Procedure under Paragraph 1. Paragraph 1 in Section
303 states: “Competition — A Reliability Standard shall not give any
market participant an unfair competitive advantage.” Furthermore,
the exclusion of the collector system for I4 generators is the only
incident of a non-contiguous BES in the BES definition. The collector
systems are solely used by I4 generators to aggregate generation; they
have no local distribution application and therefore to do come under
the local distribution exemption in the core BES definition (i.e., the
BES definition “does not include facilities used in the local distribution
of electric energy”).
Response: The SDT cannot assume that the intervening equipment cited is solely used as a collector system. There are too many
variables and configurations across the continent to allow for the assumption that collector systems are only utilized for the sole
purpose of aggregating dispersed power resources. Therefore on a ‘bright-line’ basis, the SDT only included those portions of the
collector system that are strictly utilized for delivering the aggregated capacity of the dispersed power resources to the
interconnected transmission system. The intervening equipment cited is being treated in a similar fashion to Cranking Paths. The
revised Reference Document will show specific examples. Furthermore, it is not clear that Inclusion I4 presents a competitive
advantage to certain types of generation or conversely, a disadvantage to some types of generation, as a class and no evidence has
Consideration of Comments: Project 2010-17 October 2013
23
Organization
Yes or No
Question 1 Comment
been presented to make that case. While SDT’s must respect competitive aspects of definitions/requirements, the primary function
of an SDT is to promote reliability and that is what the SDT believes it has done in this case. Where collector systems support the
reliable operation of the surrounding interconnected transmission system and do not have a distribution function, those excluded
facilities may be candidates for inclusion through the BES Exception Process. No change made.
Southern California Edison Company
No
Consideration of Comments: Project 2010-17 October 2013
Phase 2 of the BES definition characterizes dispersed power producing
resources as being “small-scale” power generation technologies.
However, although this characterization is currently the norm, that
could easily change in the future. As written, I4 creates an ambiguity
for Dispersed Power Producing Resources that are greater than or
equal to 75MVA, because these generation resources appear to be
included within the BES under both the I2 and I4 inclusions. The
problem this creates is that I2 and I4 address the connection facilities
differently, with I2 beginning at the generator terminals, while I4
begins at the point where the resources aggregate to greater than 75
MVA. SCE believes that the SDT should clarify which of these
inclusions should apply to dispersed power producing resources
greater than or equal to 75MVA.SCE is also concerned about how I4
could potentially discourage the development of common points of
interconnection (i.e. collector substations) for multiple projects in
queue, especially in relation to the E1 and E3 exclusions. In SCE’s
experience, “plans of service” that include common collector
substations for multiple generation projects can be an effective way to
encourage development of renewable resources in renewable-rich
areas. However, such resources develop and interconnect as
individual projects under separate development paths. The first
distributed generation projects connecting to such stations may find
their resources initially classified as non-BES if the aggregate
generation is less than 75 MVA. However, later projects connecting to
the same common point could find the BES status changing as
additional generation projects materialize at the same collector
24
Organization
Yes or No
Question 1 Comment
substation. SCE is concerned that this will discourage dispersed
generation developers from pursuing common points of
interconnection at collector substations built for such purpose in
renewable rich areas. The aggregate total of the projects further
down the interconnection queue could also trigger system upgrades,
based on TPL studies for which the owners of these projects would be
responsible.
Response: The SDT crafted Inclusions I2 and I4 to address the possibility of future, larger, individual dispersed power producing
resources. If a single unit is greater than 20 MVA then it is covered by Inclusion I2 regardless of the type of generation. For smaller
dispersed power producing resources Inclusion I4 takes precedence. The SDT believes that the distinction is clear. In addition, the
SDT can’t predict future building or interconnection plans. No change made.
American Wind Energy Association
No
Consideration of Comments: Project 2010-17 October 2013
1. The technical rationale for not including individual generators in the
BES definition is that these individual generators cannot affect BES
reliability. Whatever technical rationale drove the drafting team’s
decision to not include the collector array components in the BES
definition would also dictate that the individual turbines connected by
that collector array should also not be included in the BES definition.
We cannot think of any technical rationale that would justify including
individual wind turbines in the definition but not including the
collector array that aggregates those individual generators.
Regardless, the burden for providing technical rationale should fall on
the drafting team to demonstrate that including individual generators
will improve electric reliability. That burden has not been met, and the
standards drafting team has made no attempt to provide that
rationale, despite repeated requests to do so. As explained below,
that burden cannot be met, as there is no benefit to including
individual generators, and including them in the definition is only
likely to provoke significant confusion that distracts from real efforts
to improve electric reliability. The only compelling reason for applying
25
Organization
Yes or No
Question 1 Comment
BES standards to individual dispersed generators would be if there
were a real risk of an abrupt common mode failure affecting a large
share of the dispersed generators in a >75 MVA wind plant. However,
per FERC Order 661A, wind turbine generators already comply with
voltage and frequency ride-through standards that are far more
stringent than those that apply to other types of generators. As a
result, if a common mode failure caused by a grid disturbance were to
affect the wind turbines in a >75 MVA wind plant, the impact on the
wind plant would be irrelevant for grid reliability because the voltage
and/or frequency deviation would have already caused most if not all
of the conventional generators in the grid operating area to trip
offline. While weather-driven changes in wind speed can significantly
change the aggregate output of a wind plant, those changes in output
occur too gradually to pose a risk to bulk power system reliability, and
regardless such changes in output would not be regulated or
mitigated by BES-relevant standards. No compelling rationale has
been offered for why including individual dispersed wind turbine
generators in the BES definition will improve grid reliability. Until one
is offered, we will continue to oppose the inclusion of individual wind
turbine generators in the BES definition.
2. We request clarification on the intent of the FERC direction
provided in Orders 773 and 773-A regarding inclusion of dispersed
generation, as we disagree with the standards drafting team’s
interpretation that those orders required the inclusion of individual
dispersed generators. After careful study, it appears that the proposed
standard for the I4 inclusion of dispersed generation is broader in
scope than the intent as stated in the Orders. The critical language
appears in Order 773-A, under item number 54. Here, FERC approves
the dispersed power inclusion I4, “...finding it provides useful
granularity...”, and that it agreed it is appropriate “to expressly cover
Consideration of Comments: Project 2010-17 October 2013
26
Organization
Yes or No
Question 1 Comment
dispersed power producing resources utilizing a system designed
primarily for aggregating capacity.” We believe that the second
sentence should be further examined for proper intent. Our
interpretation of this sentence is that collector systems aggregating
dispersed power at a level of 75 MVA or more is the level of intended
inclusion. This means that, in the example of a wind farm larger than
75 MVA, the application of the BES definition and all the requisite
applicable standards is only at points where the aggregated capacity is
greater than 75 MVA. This interpretation has several advantages: it is
consistent with the current output threshold value; it does not
establish a new, lower threshold for the BES definition; and it applies
requirements where appropriate, i.e. equipment that carries 75 MVA
and is therefore of sufficient size to be relevant to the reliability of the
BES. Aggregator collection systems are designed to employ protection
system equipment at the aggregation node, as well as operational
output status monitoring equipment, and other equipment important
to support grid reliability and monitoring at that aggregation point.
Nowhere in the relevant FERC Orders does the language expressly
require the inclusion of individual dispersed generators (PV panels,
wind turbines, flywheels, microturbines, etc.). We believe that
deletion of I4 (a) meets the intent of the FERC direction and properly
supports grid reliability.
3. FERC Order 773-A goes on to say in part 60 that, indeed, dispersed
power producers with greater than 75 MVA nameplate capacity are
already registered. For many registered entities across the country,
the interpretation has been to apply the body of NERC standards at
the point of aggregation. This regional entity interpretation of NERC
standard applicability at the aggregation point is comparable to the
interpretation described above, and is based on sound reliability
thresholds and knowledge of dispersed power system design.
Consideration of Comments: Project 2010-17 October 2013
27
Organization
Yes or No
Question 1 Comment
4. The term "individual resources" utilized in I4 (a) is unclear, and
could refer to the wind plant as a whole. What constitutes an
"individual resource?” More technically precise language should be
utilized to specifically identify what resources are intended to be
included per this bullet.
5. In the last two postings, we and other commenters have asked
specific technical questions that have not been answered. Instead, we
have received only a generic reply that the SDT believes our concerns
would best be addressed through clarification of the applicability of
individual reliability standards. Please provide specific replies to the
following questions: a. In the August 21, 2013 webinar, the BES
definition drafting team indicated that its justification for the 75 MVA
aggregating threshold in I4 (b) was that 75 MVA is the level that the
drafting team believes that single failures resulting in the loss of
generation could have an appreciable impact on the grid. It seems
inconsistent that a 2 MVA individual dispersed generator is deemed
significant to reliability but the equipment that is utilized to connect
individual dispersed generators totaling to <75 MVA is deemed not
significant to reliability. Please explain the technical rationale for
concluding that an individual dispersed generating asset rated at 2
MVA is important to grid reliability but that a collector feeder which
may impact up to 37 of these individual dispersed generating assets is
not critical to reliability?
b. Since the collector feeders are excluded from the BES definition so
that there is not a contiguous BES connection between the individual
dispersed generating asset and the grid, please explain the technical
rationale for concluding that an individual 2 MVA dispersed generator
at a facility rated at greater than 75 MVA has more impact on the BES
than does an identical 2 MVA dispersed generator at a facility rated at
less than 75 MVA? If the impact on grid reliability of both units is the
Consideration of Comments: Project 2010-17 October 2013
28
Organization
Yes or No
Question 1 Comment
same, why is one considered BES and the other is not?
c. In the Consideration of Comments document for the first draft of
the Phase II BES definition, the Drafting Team acknowledged that
there are both existing and pending reliability standards which likely
will need to be reviewed and revised to clarify or correct the
applicability of the standard requirements to dispersed generation.
Please identify the reliability gaps being addressed by including
individual dispersed generating assets within the BES definition. In
other words, what specific existing or pending NERC Reliability
Standard Requirements are perceived as being needed to be applied
to individual dispersed generating assets to maintain grid reliability?
6. We appreciate that the SDT acknowledges that numerous existing
and pending standards will need to be reviewed and revised to clarify
standard applicability to individual generating units. However, we do
not believe that implementation of the BES definition should go
forward until this review and revision of other standards has been
completed. Relative to the approval and implementation time frames
being discussed for the new BES definition, we do not believe any such
action could be taken in a timely enough fashion to resolve industry
uncertainty and avoid a major regulatory burden that would distract
from efforts that actually improve grid reliability. Without that review,
there will simply be too much ambiguity in the requirements as they
apply to individual dispersed generating assets and there will be too
much compliance effort spent on trying to apply these ambiguous
requirements with no commensurate gain in reliability. As currently
written, the definition will create much regulatory uncertainty in how
auditors will assess an entity's compliance with these ambiguous
requirements. Including individual dispersed generators in the BES
definition will cause a major diversion away from efforts that improve
BES reliability, as entities are forced to simultaneously seek relief via
Consideration of Comments: Project 2010-17 October 2013
29
Organization
Yes or No
Question 1 Comment
the Exception Process to exclude individual dispersed generators that
are insignificant from a reliability standpoint from their programs
while at the same time attempting to modify their existing compliance
programs to accommodate individual dispersed generators in the
event that the exception applications are not approved. With more
than 45,000 wind turbines installed in the U.S. and the vast majority of
them in wind plants larger than 75 MVA, NERC will be faced with a
huge backlog of exception requests for small distributed generators
while Generator Owners with dispersed generating assets struggle to
implement reliability standards that were never drafted with the
intent of being applicable to anything but large scale generating
stations. As a result, proceeding with the BES definition as currently
drafted would actually impair, rather than improve, bulk electric
system reliability. Examples of standards that were not drafted with
small dispersed generators in mind include: o PRC-005-2 Protection
System testing - the relay test requirements were developed with
large generators in mind, and differ significantly from requirements in
FERC Order 661A, of 2005 that require wind plants to meet Low
Voltage Ride-Through (LVRT) and Power Factor Design Criteria. These
standards significantly change the protection scheme applied to
individual turbines, and there is no clarity about how they should be
applied. Wind turbine protection systems are often integral to the
wind farm control system and the PRC-005-2 requirements were
developed for protection equipment typically applied to large-scale
generation, not wind farm control systems. o TOP-002 Normal
Operations Planning - Under R14 of this standard, an unplanned
outage for any individual wind turbine would require a status
notification report from the GO to the TO/TOP. While such a report
can be important for large central station generation, it would provide
no value for a small individual wind turbine generator. This level of
Consideration of Comments: Project 2010-17 October 2013
30
Organization
Yes or No
Question 1 Comment
reporting, at typically less than 3 MVA, is much lower that any
practical reliability threshold, and would simply result in a
documentation effort with no value. Similar concerns exist for FAC008-3, PRC-001-1, PRC-004-2a, PRC-019-1, PRC-024-1, and PRC-025-1,
and other standards in which small-scale dispersed generators were
not considered during the standards’ development. Unless Inclusion
I4 (a) is eliminated, or significantly revised to clarify that the only BESrelevant standards that apply to dispersed generators are those that
affirmatively state that they apply to dispersed generators, we do not
believe implementation of the new BES definition should go forward
until all reliability standards have been reviewed and revised as
necessary to clarify the applicability to individual dispersed generating
assets. What reliability benefit is there to a "bright line" BES definition
if there is not a corresponding clarity in the applicability of reliability
standards to the elements deemed to be included in the BES?
7. If the standards drafting team does not delete I4 (a) as requested
above, we ask that I4 (a) be modified to clarify that the only BESrelevant standards that apply to individual dispersed generators are
those that affirmatively state that they apply to dispersed generators.
This will help avoid the harmful consequences of attempting to apply
standards that were not written with dispersed generators in mind to
dispersed generators.
Response: 1. Individual dispersed power producing resources are already included in the BES when they aggregate to greater than 75
MVA. Nothing in Phase 2 of this project has changed that fact which was established in earlier versions of the definition and clarified
by FERC Orders 773 and 773-A. Technical justification must be supplied in order to remove something from an approved definition
or standard. Simply stating that a unit doesn’t impact reliability is not technical justification but a simple declaration of opinion
without facts to back up the statement. No change made.
2. The SDT does not agree with your interpretation of FERC’s statements. FERC staff is represented on the SDT on an observer basis
Consideration of Comments: Project 2010-17 October 2013
31
Organization
Yes or No
Question 1 Comment
and has confirmed the SDT’s interpretation of the cited sentences. No change made.
3. One of the main reasons for revising the BES definition was FERC’s desire for a bright-line standard that obviated regional
discretion in interpreting and applying the definition. No change made.
4. The SDT believes the term is clear and understood by the industry. No change made.
5a. The SDT cannot assume that the intervening equipment cited is solely used as a collector system. There are too many variables
and configurations across the continent to allow for the assumption that collector systems are only utilized for the sole purpose of
aggregating dispersed power resources. Therefore on a ‘bright-line’ basis the SDT only included those portions of the collector
system that are strictly utilized for delivering the aggregated capacity of the dispersed power resources to the interconnected
transmission system. The intervening equipment cited is being treated in a similar fashion as Cranking Paths. The revised Reference
Document will show specific examples. Where collector systems support the reliable operation of the surrounding interconnected
transmission system and do not have a distribution function, those excluded facilities may be candidates for inclusion through the
BES Exception Process. No change made.
5b. Threshold values for generation were vetted in a report supplied to the SDT by the NERC Planning Committee and which can be
found at:
http://www.nerc.com/pa/Stand/Project%20201017%20Proposed%20Definition%20of%20Bulk%20Electri/bes_phase2_pc_report_fin
al_20130306.pdf The threshold values identified in Inclusion I4 are comparable to the values identified in Inclusion I2. No change
made.
5c. Qualified dispersed power producing resources were included in the BES prior to the start of this project. Standards that were
relevant at that time are still relevant today. The SDT did review existing standards and believes that no changes are necessary due
to the revised definition. No change made.
6. and 7. A SAR has been submitted to the NERC Standards Committee to address the applicability of small, dispersed generating
resources within the body of the existing standards. (See:
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_20131017a_agenda_package.pdf - item 5.) Deleting
those units from the definition at this time could cause a reliability gap. The proper procedure is to continue to include these units in
the BES and allow the project initiated by the SAR to determine when such units can be safely removed from specific standard
applicability. No change made.
Midwest Reliability Organization
No
Consideration of Comments: Project 2010-17 October 2013
In the MRO opinion, the BES definition should not have included
32
Organization
Yes or No
Question 1 Comment
individual resources of a dispersed power producing resource.
Instead, the Regions could have opted to include any that had a
material impact to reliability - just the opposite of the way the BES
definition was written. NERC talks of a guidance document in order to
define those resources which are a part of the BES. This does not bear
much weight when put towards a FERC approved definition and FERC
approved Reliability Standards. The notion to use the BES
implementation period of two years to work with the Standards
Committee in order to revise the standards identified as requiring
revisions doesn’t seem workable. The implementation period is the
time that has been identified for Registered Entities to bring their
programs into compliance, it is not reasonable to expect the entities
to expend their resources to bring their programs up to date with the
possibility of the standards not being applicable. Nor is it reasonable
to expect entities to postpone implementing programs in anticipation
of standards being revised prior to the end of the implementation
period.
Response: One of the main reasons for revising the BES definition was FERC’s desire for a bright-line standard that obviated regional
discretion in interpreting and applying the definition. Material impact studies do not lend themselves to a bright-line concept such as
was desired by FERC. A SAR has been submitted to the NERC Standards Committee to address the applicability of small, dispersed
generating resources within the body of the existing standards. (See:
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_20131017a_agenda_package.pdf - item 5.) Deleting
those units from the definition at this time could cause a reliability gap. The proper procedure is to continue to include these units in
the BES and allow the project initiated by the SAR to determine when such units can be safely removed from specific standard
applicability. No change made.
Tri-State Generation and Transmission
Association, Inc.
No
Consideration of Comments: Project 2010-17 October 2013
Tri-State disagrees that FERC Orders 773 and 773-A approved the
inclusion of individual dispersed generating units that are individually,
or in aggregate, below the capacity that requires the owner to register
as a Generator Owner. Inclusion I4 of the current draft of the BES
33
Organization
Yes or No
Question 1 Comment
definition does require that under various scenarios. It is apparent
from the comments to draft 2 of the Definition, and the questions
during the webinar that was held by the drafting team, that Inclusion
I4a) is disputed by a large percentage of registered entities and there
is no technical basis for its inclusion in the definition. When asked
during the webinar whether the drafting team had approached FERC
regarding whether all individual dispersed units were to be included
and about the fact that there was no technical justification for such
inclusion, the drafting team simply stated that the FERC staff do not
speak for the Commission. While it is be true that the staff do not
speak for the Commission, all the drafting teams have FERC staff
available that are able to convey the thoughts of the drafting teams
and industry to the Commission. Tri-State agrees that the collection
system for dispersed generation that aggregates to 75 MVA or more is
important to include in the definition, since a single contingency could
lead to loss of a large magnitude of generation. But loss of an
individual small generator, oftentimes 2 MVA or less, has no direct
consequence to the reliability of the BES.
Response: FERC staff is represented on the SDT on an observer basis and has consistently upheld Inclusion I4. No change made.
EDP Renewables North America LLC
No
Consideration of Comments: Project 2010-17 October 2013
EDP Renewables North America LLC (EDPR NA) disagrees with the
inclusion of individual dispersed power producing units (individual
wind turbines and solar units (inverters)) in the definition of I4.
Individual wind turbines have negligible or no effect on the reliability
of the BES due to their generating capacity and the fact that they are
intermittent resources. Inclusion of individual wind turbines would
require a wind generator to consider each wind turbine in its
compliance program for Standards such as PRC-005. Since there is no
discrete equipment, outside of the turbine control system, in a wind
turbine that could logically be included in a wind generator’s
34
Organization
Yes or No
Question 1 Comment
Protection System devices to be tested and maintained, the wind
generator would be forced to seek exclusion under the Applicability
section of other affected Standards. This would impose an
administrative burden not only on the wind generation companies but
also on each of the NERC Regional Entities, and indeed NERC itself, to
consider each of the affected Registered Entity’s request for exclusion
from Applicability with certain of the currently enforceable Standards.
In addition, inclusion of individual wind turbines in I4 would require
revisions to each of the applicable Reliability Standards, a lengthy
process. Compliance with many standards including the following
would be required for such low level BES elements: FAC-003, PRC-001,
PRC-004, PRC-005, and VAR-002. The SDT is asking for technical
reasons for disagreement with the language; however, EDPR NA
believes that the SDT has not provided sound technical reasons for
inclusion of individual dispersed power producing units in
I4.Suggested language change: I4: The point at which the aggregation
equals to a capacity threshold of 75 MVA or above.
Response: Individual dispersed power producing resources are already included in the BES when they aggregate to greater than 75
MVA. Nothing in Phase 2 of this project has changed that fact which was established in earlier versions of the definition and clarified
by FERC Orders 773 and 773-A. Technical justification must be supplied in order to remove something from an approved definition
or standard. Simply stating that a unit doesn’t impact reliability is not technical justification but a simple declaration of opinion
without facts to back up the statement. No change made.
Pacific Gas and Electric Comapny
Yes
Consideration of Comments: Project 2010-17 October 2013
We support the definition as posted and commend the drafting team
for considering the comments from the industry and weighing those
industry comments against the FERC directives. Many of the industry
comments take a different direction and opinion from the FERC
directives and we recognize that the definition is a compromise on the
positions of all stake holders. It provides a bright line that will
improve reliability and provide a consistent process across North
35
Organization
Yes or No
Question 1 Comment
America to address exceptions.
Duke Energy
Yes
Dominion
Yes
Bonneville Power Administration
Yes
American Electric Power
Yes
Ameren
Yes
South Carolina Electric and Gas
Yes
Manitoba Hydro
Yes
Idaho Power Co.
Yes
Duke Energy supports the proposed clarifications to I4 made by the
SDT.
Response: Thank you for your support.
Consideration of Comments: Project 2010-17 October 2013
36
2. Are there any other concerns with this definition that haven’t been covered in previous postings, questions and comments?
Summary Consideration: The SDT appreciates the concerns raised in the comments but found no compelling arguments to make any
changes to the posted definition.
The SDT has retained the language of Inclusion I4 to clearly reflect the SDT’s intent to include individual dispersed power producing units
(such as wind and solar units) that aggregate to greater than 75 MVA, along with the collector system that connects these units, from
the point they aggregate to greater than 75 MVA to the point of connection at 100kV or higher. While the SDT recognizes that some
stakeholders do not agree with the inclusion of individual dispersed power producing units, FERC Orders 773 and 773-A approved the
inclusion of these individual units. No stakeholder has provided a technical rationale to support removal of the individual units from the
definition. The SDT believes that stakeholder concerns about inclusion of individual units may be addressed by specifying the Facilities to
which an individual standard applies within the Applicability section of that standard.
The SDT will be revising the Reference Document once the Phase 2 project is completed and will post it for comments as was done with
the Phase 1 version. Comments on specific sections and diagrams will be considered at that time.
Organization
Yes or No
Alliant Energy
No
Question 2 Comment
No - Alliant Energy still believes strongly that including individual dispersed
generators (I4) as part of the BES does nothing to maintain/increase the reliability of
the BES, and creates an extremely difficult compliance process. It will also create a
very large backlog of exception requests, as most dispersed generator owners will
request an exception for their generators.
Response: Such units are only included when they aggregate to greater than 75 MVA and this fact hasn’t changed with the revised
definition. No change made.
Northeast Power Coordinating
Council
No
North Carolina Electric
No
Consideration of Comments: Project 2010-17 October 2013
37
Organization
Yes or No
Question 2 Comment
Membership Corporation
ACES Standards Collaborators
No
SPP Standards Review Group
No
Dominion
No
Duke Energy
No
Associated Electric
Cooperative, Inc. - JRO00088
No
PacifiCorp
No
Bonneville Power
Administration
No
Pacific Gas and Electric
Comapny
No
Cowlitz PUD
No
Consumers Energy
No
Madison Gas and Electric
Company
No
South Carolina Electric and
Gas
No
Consideration of Comments: Project 2010-17 October 2013
38
Organization
Yes or No
Manitoba Hydro
No
WPSC
No
MidAmerican Energy
Company
No
Midwest Reliability
Organization
No
Tri-State Generation and
Transmission Association, Inc.
No
Question 2 Comment
Response: Thank you for your response.
Arizona Public Service
Company
Yes
Everything that has been excluded from the BES definition should also be excluded
from I5 for reactive sources, because there is no impact to the BES. For example, if a
radial system (E1) is excluded because it does not have an impact on the BES, a
reactive resource connected at the end of the radial system is not likely to have an
impact on the BES either.
Response: The SDT established Exclusion E4 to allow for exclusion of qualified reactive resources. No change made.
Southern Company: Southern
Company Services, Inc.;
Alabama Power Company;
Georgia
Yes
Southern Transmission believes that Exclusion E3 should include a limit on the size of
a Local Network (LN). The facilities that will comprise these LNs are currently part of
the BES and subject to all applicable standards. To allow these facilities to now be
excluded from the BES without regard to some size limitation could result in negative
impacts on the BES in the future. Southern Transmission believes that without
placing a size limitation on such a network, a single contingency could result in
significant flows across the BES to serve the LN from a different location.
Additionally, there is concern that the exclusion has no requirement for power to
Consideration of Comments: Project 2010-17 October 2013
39
Organization
Yes or No
Question 2 Comment
only flow into the LN for N-1 conditions. Southern Transmission does agree that
there may be limited locations where such an exemption could be appropriate, but
would prefer to see the facilities initially included in the BES and have the
Transmission Owner go through a review process with the Regional Reliability
Organization to provide justification for classifying facilities as a LN.
Response: The SDT does not agree with the blanket statement that facilities that comprise a local network are necessarily part of the
BES now and subject to applicable standards; that would need to be examined on a case-by-case basis. The SDT included the 300 kV
voltage threshold limit which established a de facto size limitation on local networks. This concept was applied to real-world
scenarios during the development of the definition and was accepted by the Commission (FERC) in Phase 1. The SDT has made it
clear that local network criteria must be met for any and all operating conditions. No change made.
PPL NERC Registered Affiliates
Yes
These comments are submitted on behalf of the following PPL NERC Registered
Affiliates (PPL): Louisville Gas and Electric Company and Kentucky Utilities Company;
PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL
Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are
registered in six regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of
the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and
TSP.
1. The PPL NERC Registered Affiliates previously commented that the language of the
proposed BES definition is subject to multiple interpretations and is therefore difficult
to apply correctly without the Reference Document. The Reference Document is not
complete or final for the Phase 2 BES definition, however. The Reference Document
contains a disclaimer on p.1 that states “...this reference document is outdated.
Revisions to the document will be developed at a later date to conform to the
definition being developed in Phase 2.” In response to the PPL NERC Registered
Affiliates’ concerns regarding the unavailability of a Reference Document to reflect
the Phase 2 BES definition, the SDT stated in response that it “did not intend the
posted version to represent a full implementation of Phase 2 as Phase 2 isn’t
complete.” The PPL NERC Registered Affiliates are concerned by this response
Consideration of Comments: Project 2010-17 October 2013
40
Organization
Yes or No
Question 2 Comment
because, unless it is clarified, the existing Phase 1 Reference Document could be
interpreted to bring into the Phase 2 BES definition facilities that are not, and do not
need to be, part of the BES. For example, the words in the existing Reference
Document may imply that NERC registration for very small, standby, non-Blackstart
Resource generators feeding the auxiliary buses of generation plants for emergency
purposes is required. Specifically, Figure I2-5 of the Reference Document states that
all units in a plant are part of the BES regardless of size, if the plant totals more than
75 MVA, if they "contribute to the gross aggregate rating of the site."The SDT said in
response to our earlier comments regarding small standby diesels that, “The intent of
the SDT is that the precedent will not change how the identified equipment is
classified.” However, Figure I2-5 of the Reference Document appears to do exactly
that. If for example a 500 MW plant has a 2 MW diesel generator feeding the 4kV
bus for emergency purposes (but not as a Blackstart Resource), the facility could be
said to have a gross aggregate nameplate rating of 502 MW when the diesel is
running - the aggregate nameplate rating has increased. Fig. I2-5 moreover includes
in the BES units that feed transformers with a high-side voltage less than 100 kV, if
their output is eventually stepped-up to a plant outlet that is > 100 kV. While, one
could cite Fig. S1-9b,as indicating that generators feeding a bus that is exclusively an
importer of power are not part of the BES, it would be far better to state matters
explicitly in the first place. The contribute-to-aggregate-capability language of the
present (and outdated) Reference Document does not appear in the BES definition
and it is unclear. Item I2b of the BES definition should therefore be accompanied by
a footnote saying that, “Standby and emergency generators that feed auxiliary buses
are not considered in determining the plant/facility aggregate nameplate rating,” or
“Standby and emergency generators are not considered in determining the
plant/facility aggregate nameplate rating if they feed an auxiliary bus that is a net
importer of power.” Further, an example should be added to the Resource
Document that shows that Emergency Diesels and standby units that feed auxiliary
buses that are net importers of power are not part of the BES (unless they are
Blackstart Resources).
Consideration of Comments: Project 2010-17 October 2013
41
Organization
Yes or No
Question 2 Comment
2. The PPL NERC Registered Affiliates also previously commented that the generic
term "nameplate rating" should be replaced by the NERC-defined term "Facility
Rating." The SDT declined to make this change, because it stated Facility Ratings,
“fluctuate from period to period. “ The PPL NERC Registered Affiliates continue to
believe that the use of the term “Facility Rating” is more appropriate. Consider for
example four simple-cycle CTs rated at 19 MVA each (76 MVA total) that are
connected to a 115 kV line through a single GSU rated at 72 MVA. This in a 72 MVA
plant (because of the most limiting component) and would therefore not presently be
part of the BES, but it could be pulled-in depending on whether one focuses on the
nameplate rating of the generators or the most-limiting component (in this case the
GSU). The Reference Document suggests that the former approach applies, because
in every single depiction of generation units it cites only generator ratings and
ignores GSU capability. Furthermore, using generator nameplate ratings can in
certain circumstances lead to confusion because some generators (e.g., simple cycle
CTs) can have multiple ratings (e.g., baseload, peaking and emergency ratings).To
avoid this confusion, the proposed definition should be based on the “nameplate
rating of the most-limiting component,” which in the example here presented is 72
MVA (and is also the Facility Rating). Therefore, Inclusion I2 should be revised to
read as follows:a) Gross nameplate rating of the most-limiting component of an
individual unit greater than 20 MVA, Or,b) Gross aggregate nameplate rating of the
most-limiting component(s) of a plant/facility greater than 75 MVA Additionally, the
Reference Document should be changed to provide at least one example of GSU MVA
values setting the most limiting criterion.
Response: The SDT will be revising the Reference Document once the Phase 2 project is completed and will post it for comments as
was done with the Phase 1 version. Your comments on specific sections and diagrams will be considered at that time.
The SDT believes that the continued use of the nameplate rating is a clear, appropriate, and understood term that established a
consistent bright-line approach to identifying BES Elements. No change made.
American Electric Power
Yes
AEP cannot vote in the affirmative on this project as long as BES elements (measured
Consideration of Comments: Project 2010-17 October 2013
42
Organization
Yes or No
Question 2 Comment
for compliance) are as granular as the individual dispersed power resource. We do
not see the reliability benefit (nor has the project team provided technical
justification) of tracking all of the compliance elements for individual wind turbines
when the focus should be placed on the aggregate of the facility. Does the RC want to
be notified of an outage of each individual wind turbine in real-time, or a loss of
significant portion of the wind farm? If we are not careful, we will have entities at
these resources and others monitoring them (BAs, TOPs, RCs) focusing on minor
issues that will distract from more relevant reliability needs.
Response: Individual dispersed power producing resources are already included in the BES when they aggregate to greater than 75
MVA. Nothing in Phase 2 of this project has changed that fact which was established in earlier versions of the definition and clarified
by FERC Orders 773 and 773-A. Technical justification must be supplied in order to remove something from an approved definition
or standard. Simply stating that a unit doesn’t impact reliability is not technical justification but a simple declaration of opinion
without facts to back up the statement. No change made.
Ameren
Yes
(1) When the SDT updates the Reference (Guidance) Document, we request a couple
of additions to help clarify Exclusion E3. We ask the SDT to include System Diagram
examples with a 138kV Local Network (LN) for which Real Power only flows in (from
138 to 69kV) and embedded within this LN is a 69kV network with multiple
generating units. Note that none of these generators are Blackstart Resources or
Dispersed power resources. We believe that the left side of your Figure S1-9b could
be adapted to do this. Please add the two following examples: (a) First, a 69kV
network that serves load at multiple substations and has three different substations
each with a single 13.8/69kV GSU for a single 19MVA generator with an aggregate
capacity of (3 x 19 MVA =) 57MVA within the entire 138kV LN; and (b) Second, the
same diagram as item 1a plus one additional single 13.8/69kV GSU for a single
50MVA generator to provide an aggregate capacity of (3 x 19 MVA + 50 MVA =)
107MVA within the entire 138kV LN . Our understanding is that the 138kV leads to
the 138/69kV transformers are all excluded via Exclusion E3; and that neither the
entire 69kV network nor any of the embedded generation (aggregate 57 MVA for the
first example or 107MVA for the second example) should be included by any BES
Consideration of Comments: Project 2010-17 October 2013
43
Organization
Yes or No
Question 2 Comment
Inclusion.
(2) When the SDT updates the Reference (Guidance) Document, we request one
additional item to help clarify Inclusion I2. We ask the SDT to add a new Figure I2-7
similar to Figure I2-6. In this new Figure I2-7, we request that the >100kV / <100kV
transformer on the right be removed and connected to another <100 kV location in
the network. The generator on the right with GSU high side <100kV should be
changed from 25 MVA to 88 MVA. This generator is neither a black-start resource
nor a dispersed power resource and therefore should not be included by Inclusions I3
or I4, and our understanding is that the 88 MVA generator is also not included by
Inclusion I2.
Response: The SDT will be revising the Reference Document once the Phase 2 project is completed and will post it for comments as
was done with the Phase 1 version. Your comments on specific sections and diagrams will be considered at that time.
NIPSCO
Yes
We appreciate your consideration of our previous comments and a draft
interpretation However since such interpretations and a guidance document are
already being developed for this draft standard, more clarification is probably needed
within the standard itself.
Response: The SDT believes that the definition is clear. The Reference Document simply provides diagrams that make it easier to see
how the SDT intended the definition to be implemented and does not represent interpretations of the definition. No change made.
Xcel Energy
Yes
We appreciate that the BES SDT acknowledges that numerous existing and pending
standards will need to be reviewed and revised to clarify standard applicability to
individual generating units. However, we do not believe that implementation of the
BES definition should go forward until this review and revision of other standards has
been completed. Therefore, we recommend the implementation plan for the BES
definition be contingent upon the completion of modification to applicable GO/GOP
requirements. Otherwise, there will simply be too much ambiguity in the
requirements as they apply to individual dispersed generating assets, there will be
too much compliance effort spent on trying to apply these ambiguous requirements
Consideration of Comments: Project 2010-17 October 2013
44
Organization
Yes or No
Question 2 Comment
with no commensurate gain in reliability, and in the end many of the requirements
will change and possibly no longer apply.
Response: A SAR has been submitted to the NERC Standards Committee to address the applicability of small, dispersed generating
resources within the body of the existing standards. (See:
http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_20131017a_agenda_package.pdf - item 5.) Deleting
those units from the definition at this time could cause a reliability gap. The proper procedure is to continue to include these units in
the BES and allow the project initiated by the SAR to determine when such units can be safely removed from specific standard
applicability. The SDT did complete a review of existing standards to see if changes were required to those standards due to the
revised definition. The SDT did not find any standards or requirements that needed to be changed. No change made.
Southern California Edison
Company
Yes
The 75 MVA hurdle is nothing more than an arbitrary number being used to
denote/provide a threshold for identifying the amount of generation that has a
significant effect on the BES. This number does not consider the most significant part
of what should be encapsulated in the definition which is what the “function” of the
facility(ies) are with respect to a bulk electric system operated as an integrated
network.
Response: The 75 MVA threshold is the same value that is in force today – nothing in this project has changed that value. The MVA
approach is consistent with the bright-line approach to the definition suggested by FERC. Depending on interpretations of
functionality leaves the door open for regional discretion in applying the definition. Removal of such discretion and a uniform
continent-wide approach to applying the definition was one of the main reasons for embarking on this project. No change made.
Alcoa, Inc.
Yes
An additional concern the standards development team has not adequately
addressed is the technical justification for placing compliance requirements on newly
registered industrial facilities resulting from the adoption of this definition.
Response: The SDT believes that the Phase 2 definition is consistent with the current definition and language in the ERO Statement
of Compliance Registry Criteria as it applies to the industrial facilities and does not represent a change in what facilities should or
should not be considered part of the BES. On a case-by-case basis, an entity can always use the exception process to address
situations where the bright-line definition doesn’t lend itself to what the entity considers the correct delineation of its equipment.
Consideration of Comments: Project 2010-17 October 2013
45
Organization
Yes or No
Question 2 Comment
Alternatively, if a broader review of standards applicability is seems to be necessary for a specific sub-set of
equipment/configurations, the affected entities may submit a Standards Authorization Request (SAR) to address the identified issue.
Idaho Power Co.
Yes
While we still do not agree with the categorical inclusion of individual dispersed
power producing units into the BES, we do recognize the SDT's good faith effort to
comply with FERC Orders 773 and 773-A.
We understand that modeling of dispersed power producing resources in WECC base
cases will follow regional requirements governed by regional standards.
Response: Thank you for your support.
Modesto Irrigation District
Yes
I voted No because I disagree with the criteria proposed for defining the BES. The
BES criteria should be the criteria developed by the WECC BES Definition Task Force
in the 2009-2010 time frame, which is based on extensive engineering studies. These
extensive studies showed that system elements with a material impact to the
regional interconnected system (i.e., BES elements), are those elements at which the
available short circuit MVA exceeds 6,000 MVA. This is a very simple criteria based
on sound engineering studies, and quite unlike the current proposed definition of the
BES that we are voting on today. Thank you.
Response: Regional work such as the WECC BES Definition Task Force studies were considered as input to the SDT’s deliberations in
Phase 1 of the BES definition project. However, material impact studies are not conducive to the bright-line approach that FERC
directed and Phase 1 of this project which was accepted by industry, the Board, and the Commission.
Seminole Electric Cooperative,
Inc.
Additionally, Seminole is re-submitting the following comments from past ballots,
because Seminole still believes that these comments are practical requests that
should be incorporated into the BES definition.(1) The terms “plant” and “facility” are
not defined and are ambiguous. Please provide quantitative and/or qualitative
factors that an entity can utilize in determining what is a plant or facility. See
Inclusion I2. Seminole acknowledges that there is draft guidance covering these
terms; however, Seminole reasons that descriptive language covering these terms
Consideration of Comments: Project 2010-17 October 2013
46
Organization
Yes or No
Question 2 Comment
should be passed in conjunction with the BES definition.
(2) The following note will be placed in the Reference document:”Dispersed power
producing resources are small-scale power generation technologies using a system
designed primarily for aggregating capacity providing an alternative to, or an
enhancement of, the traditional electric power system.”Please strike the phrase “or
an enhancement of,” as it is more of a persuasive statement than an objective
statement.
(3) In Exclusion E1(c), please clarify that reactive devices, such as capacitor banks, can
also be included in this section. Reactive devices are differentiated from real power
devices in Inclusion I2, so we request clarification that reactive devices can be
included in Exclusion E1(c), i.e., please add clarification to the definition.
Response: 1. The SDT believes that the majority of the industry is comfortable with the terminology and that the Reference
Document adequately covers the concerns cited in the comment. No change made.
2. The SDT will consider your comment when it revises the Reference Document.
3. The SDT established Exclusion E4 to address the potential exclusion of qualified reactive resources. No change made.
Hoosier Energy Rural Electric
Cooperative, Inc.
The proposed language in Inclusion I4 further complicates the BES definition.
According to the Phase 1 definition, dispersed power producing units would only be
included if the units reached the 75 MVA aggregate threshold. There is nothing in the
Phase 1 definition that would include collector system equipment. The Phase 2
definition is problematic because there is uncertainty regarding the scope of
equipment that that would be included as a portion of the collector system. This
ambiguity has raised concerns that regional compliance staff may ultimately
determine a different set of equipment is included in the BES than the registered
entity will leaving the burden on the registered entity to argue why certain elements
should not be included in the BES. This will lead to inconsistent compliance
outcomes. We cannot support a definition with vague and ambiguous language that
could result in negative compliance implications during registration, audits, and
Consideration of Comments: Project 2010-17 October 2013
47
Organization
Yes or No
Question 2 Comment
enforcement processes. Furthermore, we do not believe any part of the collector
system should be included in the definition.
Response: FERC Orders 773 and 773-A directed the SDT to consider collector systems as part of Phase 2. The SDT has addressed
those collector systems in a clear fashion that leaves no room for arbitrary determinations. Furthermore, no change has been made
to the definition as to the inclusion of individual units in Phase 2 – units are still only included if they aggregate to greater than 75
MVA. No change made.
END OF REPORT
Consideration of Comments: Project 2010-17 October 2013
48
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
4. Second posting and ballot completed 9/14/13
5. Third posting and ballot completed 10/29/13
Proposed Action Plan and Description of Current Draft:
This draft is the for the recirculation ballot for the Phase 2 revised definition of the Bulk Electric
System (BES).
Future Development Plan:
Anticipated Actions
Anticipated Delivery
1. Recirculation ballot
4Q13
2. BOT adoption
4Q13
Final Ballot – November 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773‐A
Final Ballot – November 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells.
(to be removed from final draft – will be moved to the Reference Document)
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
Final Ballot – November 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
Final Ballot – November 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Final Ballot – November 2013
Page 5 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development Roadmap
This section is maintained by the drafting team during the development of the definition and will be
removed when the definition becomes effective.
Development Steps Completed:
1. SAR posted for comment 1/4/12 – 2/3/12
2. SC authorized SAR for development 4/12/12
3. First posting and initial ballot completed 7/12/13
4. Second posting and ballot completed 9/14/13
5. Third posting and ballot completed 10/29/13
Proposed Action Plan and Description of Current Draft:
This draft is the third comment posting and successivefor the recirculation ballot for the Phase 2 revised
definition of the Bulk Electric System (BES).
Future Development Plan:
Anticipated Actions
1. Additional ballot
Anticipated Delivery
October 2013
2.1.Recirculation ballot
4Q13
3.2.BOT adoption
4Q13
Draft 3 – SeptemberRecirculation – November 2013
Page 1 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition shall
become effective on the first day of the second calendar quarter after Board of Trustees adoption or as
otherwise made effective pursuant to the laws of applicable governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
January 25,
2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773‐A
Draft 3 – SeptemberRecirculation – November 2013
Page 2 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms. Terms already defined in the Reliability
Standards Glossary of Terms are not repeated here. New or revised definitions listed below will be
balloted in the same manner as a Reliability Standard. When the approved definition becomes
effective, the defined term will be added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded by application of Exclusion E1 or E3.
I2 – Generating resource(s) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources that aggregate to a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed primarily for
delivering such capacity to a common point of connection at a voltage of 100 kV or above.
Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells.
(to be removed from final draft – will be moved to the Reference Document)
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1 unless excluded by application of Exclusion E4.
Exclusions:
Draft 3 – SeptemberRecirculation – November 2013
Page 3 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with
an aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected
system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the
level of service to retail customers and not to accommodate bulk power transfer across the
interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusions I2, I3, or I4 and do not have
Draft 3 – SeptemberRecirculation – November 2013
Page 4 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain any part of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within
the Western Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft 3 – SeptemberRecirculation – November 2013
Page 5 of 5
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Standard Development TimelineRoadmap
This section is maintained by the drafting team during the development of the standarddefinition and
will be removed when the standarddefinition becomes effective.
Development Steps Completed:
1. SAR posted for comment 12/17/10 – 1/21/114/12 – 2/3/12
2. SC authorized moving the SAR forward to standard for development 3/25/114/12/12
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11
5.3.Second posting of definition and criteria plus initial ballot 8/26/11 – 10/10/11completed
7/12/13
4. Second posting and ballot completed 9/14/13
5. Third posting and ballot completed 10/29/13
Proposed Action Plan and Description of Current Draft:
This draft is the third posting and for the recirculation ballot offor the Phase 2 revised definition of the
Bulk Electric System (BES). It is for a 10-day recirculation voting period.
Future Development Plan:
Anticipated Actions
Anticipated
DateDelivery
30-day Formal Comment Period
4/28/11
45-day Formal Comment Period with Parallel Initial Ballot
September 2011
1. Recirculation ballot
2. BOT adoption
November 20114Q13
January 20124Q13
Draft #2: Date
Final Ballot – November 2013
Page 1 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Draft #2: Date
Final Ballot – November 2013
Page 2 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, the definition will
go into effect shall become effective on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by or as otherwise made effective
pursuant to the definition shall begin 24 months after the laws of applicable effective date of the
definition. governmental authorities.
Version History
Version
Date
Action
Change
Tracking
1
TBDJanuary
25, 2012
Respond to FERC Order No. 743 to
clarify the definition of the Bulk Electric
System
N/A
2
TBD
Phase 2 clarifications to the original
revisions
Y
Respond to directives in FERC Orders
773 and 773-A
Draft #2: Date
Final Ballot – November 2013
Page 3 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
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 whenwill be balloted in the proposed standard is
approved.same manner as a Reliability Standard. When the standardapproved definition becomes
effective, thesethe defined termsterm will be removed from the individual standard and added to the
Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•
•
•
•
I1 - Transformers with the primary terminal and at least one secondary terminal operated at 100
kV or higher unless excluded underby application of Exclusion E1 or E3.
I2 -– Generating resource(s) with gross individual nameplate rating greater than 20 MVA or
gross plant/facility aggregate nameplate rating greater than 75 MVA including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV
or above. with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources withthat aggregate to a total capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing), and that are connected through a system
designed primarily for aggregatingdelivering such capacity, connected at to a common point of
connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
•b) The system designed primarily for delivering capacity from the point where those
resources aggregate to greater than 75 MVA to a common point of connection at a
voltage of 100 kV or above.
Dispersed power producing resources are small-scale power generation technologies
using a system designed primarily for aggregating capacity providing an alternative
to, or an enhancement of, the traditional electric power system. Examples could
include but are not limited to solar, geothermal, energy storage, flywheels, wind,
micro-turbines, and fuel cells.
(to be removed from final draft – will be moved to the Reference Document)
Draft #2: Date
Final Ballot – November 2013
Page 4 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with
a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion
I1. unless excluded by application of Exclusion E4.
Exclusions:
•
E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in InclusionInclusions I2, I3,
or I4, with an aggregate capacity less than or equal to 75 MVA (gross nameplate
rating). Or,
c) Where the radial system serves Load and includes generation resources, not
identified in InclusionInclusions I2, I3 or I4, with an aggregate capacity of nonretail generation less than or equal to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or
less, between configurations being considered as radial systems, does not affect this
exclusion.
Rationale: The drafting team has proposed a threshold of 50 kV or less
for loops between radial systems when considering the application of
Exclusion E1. The SDT used a two step approach to determine the
voltage level. As a first step, regional voltage levels that are monitored
on major interfaces, paths, and monitored elements to ensure the reliable
operation of the interconnected transmission system were examined to
determine the lowest monitored voltage level. Next, power system
analyses determined the maximum amount of power that can be
transferred through the low voltage systems, when looped, under a worst
case scenario at various voltage levels. A formal white paper has been
prepared to support this approach and is included with this posting.
•
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter
that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the
BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator
Operator, or under terms approved by the applicable regulatory authority.
Draft #2: Date
Final Ballot – November 2013
Page 5 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
•
•
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or above
100 kV but less than 300 kV that distribute power to Load rather than transfer bulk power
across the interconnected system. LN’s emanate from multiple points of connection at 100 kV
or higher to improve the level of service to retail customer Loadcustomers and not to
accommodate bulk power transfer across the interconnected system. The LN is characterized by
all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in InclusionInclusions I2, I3, or I4 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA
(gross nameplate rating) ;);
b) Real Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a monitored
Facilityany part of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored
Facility included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by installed for the sole benefit of a retail
customer solely for its own use.(s).
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.
Draft #2: Date
Final Ballot – November 2013
Page 6 of 7
Project 2010-17 Definition of Bulk Electric System (Phase 2)
Draft #2: Date
Final Ballot – November 2013
Page 7 of 7
Implementation Plan for Project 2010-17:
Definition of BES (Phase 2)
Prerequisite Approvals
None.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after the date that
the definition 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 definition
shall become effective on the first day of the first calendar quarter after the date the definition is
adopted by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Compliance obligations for the Phase 2 definition would begin:
Twenty‐four months after the applicable effective date of the definition (for newly identified
Elements), or
If a longer timeframe is needed for an entity to be fully compliant with all standards applicable
to an Element or group of Elements that are newly identified as BES when the Phase 2 definition
is applied, the appropriate timeframe may be determined on a case‐by‐case basis by mutual
agreement between the Regional Entity and the Element owner/operator, and subject to review
by the ERO.
This implementation plan is consistent with the timeframe provided in Phase 1.
PUBLIC VERSION
White Paper on Bulk Electric System
Radial Exclusion (E1) Low Voltage
Loop Threshold
September 2013
Project 2010‐17: Definition of Bulk Electric System
Table of Contents
Background ..................................................................................................................................... 1
Executive Summary ........................................................................................................................ 2
Step 1: Establishment of Minimum Monitored Regional Voltage Levels ................................... 3
Step 1 Conclusion .................................................................................................................... 6
Step 2: Load Flows and Technical Considerations ....................................................................... 7
Step 2 Conclusion .................................................................................................................. 16
Study Conclusion .......................................................................................................................... 17
Appendix 1: Regional Elements ................................................................................................... 18
Appendix 2: One‐Line Diagrams…………………………………………………………………………………………….. 19
Appendix 3: Simulation Results ................................................................................................... 21
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV .......................................... 32
Bulk Electric System Radial Exclusion (E1)
Low Voltage Loop Threshold
Background
The definition of “Bulk Electric System” (BES) in the NERC Glossary consists of a core definition and a list
of facilities configurations that will be included or excluded from the core definition. The core definition
is used to establish the bright line of 100 kV, the overall demarcation point between BES and non‐BES
elements. Exclusion E1 applies to radial systems. In Order No. 773 and 773‐A, the Federal Energy
Regulatory Commission’s (Commission or FERC) expressed concerns that facilities operating below 100
kV may be required to support the reliable operation of the interconnected transmission system. The
Commission also indicated that additional factors beyond impedance must be considered to
demonstrate that looped or networked connections operating below 100 kV need not be considered in
the application of Exclusion E1.1
This document responds to the Commission’s concerns and provides a technical justification for the
establishment of a voltage threshold below which sub‐100 kV equipment need not be considered in the
evaluation of Exclusion E1.
NOTE: This justification does not address whether sub‐ 100 kV systems should be evaluated as
Bulk Electrical System (BES) Facilities. Sub‐ 100 kV systems are already excluded from the BES
under the core definition. Order 773, paragraph 155 states: “Thus, the Commission, while
disagreeing with NERC’s interpretation, does not propose to include the below 100 kV elements
in figure 3 in the bulk electric system, unless determined otherwise in the exception process.”
This was reaffirmed by the Commission in Order 773A, paragraph 36: “Moreover, as noted in the
Final Rule, the sub‐100 kV elements comprising radial systems and local networks will not be
included in the bulk electric system, unless determined otherwise in the exception process.” Sub‐
100 kV facilities will only be included as BES Facilities if justified under the NERC Rules of
Procedure (ROP) Appendix 5C Exception Process.
1
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure, Order No.
773, 141 FERC ¶ 61,236 at P155, n.139 (2012); order on reh’g, Order No. 773‐A, 143 FERC ¶ 61,053 (2013).
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 1
Executive Summary
The Project 2010‐17 Standard Drafting Team conducted a two‐step process to establish a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops do not affect the
application of Exclusion E1. The justification for establishing a lower voltage threshold for application of
Exclusion E1 consisted of a two‐step technical approach:
Step 1: A review was performed to determine the minimum voltage levels that are monitored
by Balancing Authorities, Reliability Coordinators, and Transmission Operators for Interfaces,
Paths, and Monitored Elements. This minimum voltage level reflects a value that industry
experts consider necessary to monitor and facilitate the operation of the Bulk Electric System
(BES). This step provided a technically sound approach to screen for a minimum voltage limit
that served as a starting point for the technical analysis performed in Step 2 of this study.
Step 2: Technical studies modeling the physics of loop flows through sub‐100 kV systems were
performed to establish which voltage level, while less than 100 kV, should be considered in the
evaluation of Exclusion E1.
The analysis establishes that a 50 kV threshold for sub‐100 kV loops does not affect the application of
Exclusion E1. This approach will ease the administrative burden on entities as it negates the necessity
for an entity to prove that they qualify for Exclusion E1 if the sub‐100 kV loop in question is less than or
equal to 50 kV. This analysis provides an equally effective and efficient alternative to address the
Commission’s directives expressed in Order No. 773 and 773‐A.
It should be noted that, although this study resulted in a technically justified 50 kV threshold based on
proven analytic methods, there are other preventative loop flow methods that entities can apply on
sub‐100 kV loop systems to address physical equipment concerns. These methods include:
Interlocked control schemes;
Reverse power schemes;
Transformer, feeder and bus tie protection; and
Custom protection and control schemes.
These methods are discussed in detail in Appendix 4. The presence of such equipment does not alter the
criteria developed in this white paper, nor does it influence the conclusions reached. Additionally, the
presence of this equipment does not remove or lessen an entity’s obligations associated with the bright‐
line application of the Bulk Electric System (BES) definition.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 2
Radial Systems Exclusion (E1)
The proposed definition (first posting) of radial systems in the Phase 2 BES Definition (Exclusion E1) was:
A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV
or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2 and I3, with an aggregate
capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in
Inclusions I2 and I3, with an aggregate capacity of non‐retail generation less than or equal
to 75 MVA (gross nameplate rating).
Note 1 – A normally open switching device between radial systems, as depicted on prints or
one‐line diagrams for example, does not affect this exclusion.
Note 2 ‐ The presence of a contiguous loop, operated at a voltage level of 30 kV or less2, between
configurations being considered as radial systems, does not affect this exclusion.
STEP 1 – Establishment of Minimum Monitored Regional Voltage Levels
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The groupings of these elements have different names: for instance,
Paths in the Western Interconnection; Interfaces or Flowgates in the Eastern Interconnection; or
Monitored Elements in the Electric Reliability Council of Texas (ERCOT). Nevertheless, they all constitute
element groupings that operating entities (Reliability Coordinators, Balancing Authorities, and
Transmission Operators) monitor because they understand that they are necessary to ensure the
reliable operation of the interconnected transmission system under diverse operating conditions.
To provide information in determining a voltage level where the presence of a contiguous loop between
system configurations may not affect the determination of radial systems under Exclusion E1 of the BES
definition, voltage levels that are monitored on major Interfaces, Flowgates, Paths, and ERCOT
Monitored Elements were examined. This examination focused on elements owned and operated by
entities in North America. The objective was to identify the lowest monitored voltage level on these key
element groupings. The lowest monitored line voltage on the major element groupings provides an
indication of the lower limit which operating entities have historically believed necessary to ensure the
2
The first posting of this Phase 2 definition used a threshold of 30 kV; however as a result of the study work described in
this paper, the Standard Drafting Team has revised the threshold to 50 kV for subsequent industry consideration.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 3
reliable operation of the interconnected transmission system. The results of this analysis provided a
starting point for the technical analysis which was performed in Step 2 of this study.
Step 1 Approach
Each Region was requested to provide the key groupings of elements they monitor to ensure reliable
operation of the interconnected transmission system. This list, contained in Appendix 1, was reviewed
to identify the lowest voltage element in the major element groupings monitored by operating entities
in the eight Regions. Identification of this lowest voltage level served as a starting point to begin a
closer examination into the voltage level where the presence of a contiguous loop should not affect the
evaluation of radial systems under Exclusion E1 of the BES definition.
Step 1 Results
An examination of the line listings of the North American operating entities revealed that the majority of
operating entities do not monitor elements below 69 kV as shown in Table 1. However, in some
instances elements with line voltages of 34.5 kV were included in monitored element groupings. In no
instance was a transmission line element below 34.5 kV included in the monitored element groupings.
Region
Key Monitored Element Grouping
Lowest Line Element Voltage
FRCC
Southern Interface
115
MRO
NDEX
69
Total East PJM (Rockland Electric) – Hudson Valley
NPCC
34.5
(Zone G)1
RFC
MWEX
69
SERC
VACAR IDC2
100
SPP RE
SPSNORTH_STH
115
TRE
Valley Import GTL
138
WECC
Path 52 Silver Peak – Control 55 kV
55
Notes:
1. Two interfaces in NPCC/NYISO have lines with 34.5 kV elements.
2. The TVA area in SERC was not included in the tables attached to this report; however, a review of the
Flowgates in TVA revealed monitored elements no lower than 115 kV. There were a number of
Flowgates with 115 kV monitored elements in SERC, the monitored grouping listed is representative.
Table 1: Lowest Line Element Voltage Monitored by Region
In a few rare occasions there were transformer elements with low‐side windings lower than 30 kV included in
the key monitored element groupings as shown in Table 2.
Region
Interface
Element
Voltage (kV)
NPCC/NYISO
WEST CENTRAL: Genesee (Zone
B) – Central (Zone C)
New England ‐ Southwest
Connecticut
NPCC/ISO‐NE
(Farmtn 34.5/115kV&12/115 kV) #4
34.5/115 & 12/115
SOTHNGTN 5X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐5X)
SOTHNGTN 6X ‐ Southington 115 kV
/13.8 kV Transformer (4C‐6X)
SOTHNGTN 11X ‐ Southington 115 kV
/27.6 kV Transformer (4C‐11X)
12/115
115/13.8
115/13.8
115/27.6
Table 2: Lowest Line Transformer Element Voltages Monitored by Region
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 4
Upon closer investigation, for New England’s Southwest Connecticut interface, it was determined that
the inclusion of these elements was the result of longstanding, historical interface definitions and not
for the purpose of addressing BES reliability concerns. Transformers serving lower voltage networks
continue to be included based on familiarity with the existing interface rather than a specific technical
concern. These transformers could be removed from the interface definition with no impact on
monitoring the reliability of the interconnected transmission system. For the New York West Central
interface, the low voltage element was included because the interface definition included boundary
transmission lines between Transmission Owner control areas; hence, it was included for completeness
to measure the power flow from one Transmission Owner control area to the other Transmission Owner
control area.
Further examination of the information provided by the eight NERC regions revealed that half of the
Regions only monitor transmission line elements with voltages above the 100 kV level. The other four
Regions, NPCC, RFC, MRO, and WECC, monitor transmission line elements below 100 kV as part of key
element groupings. However, in each of these cases, the number of below 100 kV transmission line
elements comprised less than 2.5% of the total monitored key element groupings. Figures 1 and 2
below depict the results of Step 1 of this study.
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 1: Voltage as Percent of Monitored Elements
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 5
Notes:
1. Data/Chart includes Transmission Lines only.
2. Data/Chart is a summary of individual elements (interfaces not included)
Figure 2: Voltage as Percent of Monitored Elements per Region
Step 1 Conclusion
The results of Step 1 of this study regarding regional monitoring levels resulted in a determination that
30 kV was a reasonable voltage level to initiate the sensitivity analysis conducted in Step 2 of this study.
This value is below any of the regional monitoring levels. As noted herein, an examination of the line
listings of the North American operating entities revealed that the majority of operating entities do not
monitor elements below 69 kV as shown in Table 1. However, in some instances elements with line
voltages of 34.5 kV were included in monitored element groupings. In no instance was a transmission
line element below 34.5 kV included in the monitored element groupings.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 6
STEP 2 ‐ Load Flows and Technical Considerations
The threshold of 30 kV was established in Step 1 as a reasonable starting point to initiate the technical
sensitivity analysis performed in Step 2 of this study. The purpose of this step was to determine if there
is a technical justification to support a voltage threshold for the purpose of determining whether
facilities greater than 100 kV can be considered to be radial under the BES Definition Exclusion E1. If the
resulting voltage threshold was deemed appropriate through technical study efforts, then contiguous
loop connections operated at voltages below this value would not preclude the application of Exclusion
E1. Conversely, contiguous loops connecting radial lines at voltages above this kV value would negate
the ability for an entity to use Exclusion E1 for the subject facilities.
This study focused on two typical configurations: a distribution loop and a sub‐transmission loop. The
study evaluated a range of voltages for the loop and the parallel transmission system with the goal of
determining the voltage level below which single contingencies on the transmission system would not
result in power flow from a low voltage distribution or sub‐transmission loop to the BES. The study
included sensitivity analysis varying the loads and impedances. Variations in loop and transmission
system impedances account for a range of physical parameters such as conductor length, conductor
type, system configuration, and proximity of the loop to the transmission system. This study provided
the low voltage floor that can be used as a consideration for BES exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 7
Analytical Approach – Distribution Circuit Loop Example
The Project 2010‐17 Standard Drafting Team sought to examine the interaction and relative magnitude
of flows on the 100 kV and above Facilities of the electric system and those of any underlying low
voltage distribution loops. While not the determining factor leading to this study’s recommendation,
line outage distribution factors (LODF) were a useful tool in understanding the relationship between
underlying systems and the BES elements. It illustrated the relative scale of interaction between the BES
and the lower voltage systems and its review was a consideration when this study was performed. As
an example, the Standard Drafting Team considered a system similar to the one depicted in Figure 3
below. In this simplified depiction of a portion of an electric system, two radial 115 kV lines emanate
from 115 kV substations A and B to serve distribution loads via 115 kV distribution transformers at
stations C and D. Stations C and D are “looped” together via either a distribution bus tie (zero
impedance) or a feeder tie (modeled with typical distribution feeder impedances).
Figure 3: Example Radial Systems with Low Voltage Distribution Loop
With the example system, the Standard Drafting Team conducted power flow simulations to assess the
performance of the power system under single contingency outages of the line between stations A and
B. The analyses determined the LODF which represent the portion of the high voltage transmission flow
that would flow across the low voltage distribution circuit or bus ties under a single contingency outage
of the line between stations A and B. To the extent that the LODF values were negligible, this indicated a
minor or insignificant contribution of the distribution loops to the operation of the high voltage system.
But, more importantly, the analyses determined whether any instances of power flow reversal, i.e.,
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 8
resultant flow delivered into the BES, would occur during contingent operating scenarios. Instances of
flow reversal into the BES would indicate that the underlying distribution looped system is exhibiting
behavior similar to a sub‐transmission or transmission system, which would call into question the
applicability of radial exclusion E1.
The study work in this approach examined the sensitivity of parallel circuit flow on the distribution
elements to the size of the distribution transformers, the operating voltage of distribution delivery buses
at stations C and D and the strength of the transmission network serving stations A and B as manifested
in the variation of the transmission network transfer impedances used in the model.
In order to simply, yet accurately, represent this low voltage loop scenario between two radial circuits, a
Power System Simulator for Engineering (PSSE) model was created. Elements represented in this model
included the following:
Radial 115 kV lines from station A to station C and station B to station D;
Interconnecting transmission line from station A to station B;
Distribution transformers tapped off the 115 kV lines between stations A and C and between
stations B and D and at stations C and D;
Feeder tie impedance to represent a feeder tie (or zero impedance bus tie) between distribution
buses at stations C and D;
Transfer impedance equivalent between stations A and B, representing the strength of the
interconnected transmission network3.
Within this model, parameters were modified to simulate differences in the length and impedance of
the transmission lines, the amount of distribution load, the strength of the transmission network
supplying stations A and B, the size of the distribution transformers and the character of the bus or
feeder ties at distribution Stations C and D.
Distribution Model Simulation
Table 3 below illustrates the domain of the various parameters that were simulated in this distribution
circuit loop scenario. A parametric analysis was performed using all combinations of variables shown in
each column of the upper portion of Table 3. Sensitivity analysis was performed as indicated in the
lower portion of the table.
3
The relative strength of the surrounding transmission system network is a function of the quantity of parallel
transmission paths and the impedance of those paths between the two source substations. A high number of parallel
paths with low impedance translates to a low transfer impedance, which allows power to more readily flow between the
stations. Conversely, a low number of parallel paths having higher impedance is represented by a relatively large
transfer impedance.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 9
Trans KV
Trans Length
115
10 miles
Sensitivity Analysis:
Dist KV
Dist Length
XFMR MVA
12.5
23
34.5
46
0 (bus tie)
2 miles
5 miles
10
20
40
Dist Load % Z Transfer
rating
40
Weak
80
Strong
Medium
Notes:
1. The “medium” value for transfer impedances was derived from an actual example system in the
northeastern US. This was deemed to be representative of a network with typical, or medium,
transmission strength. Variations of a stronger (more tightly coupled) and a weaker transmission network
were selected for the “strong” and “weak” cases, respectively. Impedance values of X=0.54%, X=1.95%,
and X=4.07% were applied for the strong, medium and weak cases, respectively.
Table 3: Model Parameters Varied
The model was used to examine a series of cases simulating a power transfer on the 115 kV line4 from
station A to station B of slightly more than 100 MW. Loads and impedances were simulated at the
location shown in Figure 5 of Appendix 2. Two load levels were used in each scenario: 40% of the rating
of the distribution transformer and 80% of the rating. Distribution transformer ratings were varied in
three steps: 10 MVA, 20 MVA, and 40 MVA. Finally, the strength of the interconnected transmission
network was varied in three steps representing a strong, medium, and weak transmission network. The
choices of transfer impedance were based on typical networks in use across North America. A specific
model from the New England area of the United States yielded an actual transfer impedance of 0.319 +
j1.954%. This represents the ’medium’ strength transmission system used in the analyses. The other
values used in the study are minimum (’strong’) and maximum (’weak’) ends of the typical range of
transfer impedances for 115 kV systems interconnected to the Bulk Electric System of North America.
Distribution feeder connections were simulated in three different ways, first with zero impedance
between the distribution buses at stations C and D, second with a 2‐mile feeder connection with typical
overhead conductor, and third with a 5‐mile connection.
Distribution Model Results
23 kV Distribution System
The results show LODFs ranging from a low of 0.2% to a high of 6.7%. In all of the cases, the direction of
power flow to the radial lines at stations A and B was toward stations C and D. In other words, there
were no instances of flow reversal from the distribution system back to the 115 kV transmission system.
The lowest LODF was found in the case with the smallest distribution transformers (10 MVA), the 5‐mile
distribution circuit tie, and the strong transmission transfer impedance. The case with the highest LODF
4
The threshold voltage of 115 kV provides conservative results. At a higher voltage, such as 230 kV, the reflection of
distribution impedance to the transmission system is significantly larger, and hence, the amount of distribution power
flow will be much smaller.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 10
was that which used the largest distribution transformers (40 MVA) with the lightest load and the use of
a zero‐impedance bus tie between the two distribution stations.
12.5 kV Distribution System
As compared to the simulations using the 23 kV distribution system, the 12.5 kV system model yielded
far lower LODF values. This result is reasonable, as the reflection of impedances on a 12.5 kV
distribution system will be nearly four times as large as those for a 23 kV distribution system, and the
transformer sizes in use at the 12.5 kV class are generally smaller, i.e., higher impedance. As with the
cases simulated for the 23 kV system, the 12.5 kV system exhibited a power flow direction in the radial
line terminals at stations A and B in the direction of the distribution stations C and D; no flow reversal
was seen in any of the contingency cases.
Given the lower voltage of the distribution system, the cases studied at this low voltage level were
limited to the scenario with the high transfer impedance value (’weak’ transmission case). This is a
conservative assumption as all cases with lower transfer impedance will yield far lower LODF values.
With that, the range of LODF values was found to be 1.0% to 6.7%. When compared with the 23 kV
system results in the weak transmission case, the range of LODF values was 1.8% to 6.7%. Higher LODF
values were found in the cases with the largest transformer size, which is to be expected.
Table 4 below provides a sample of the results of the various simulations that were conducted. The full
collection of results is provided in Appendix 3.
Case
D, KV
623a5
623a5pk
633b0pk
723c0
723c5pk
823b0
823c0
812a5
812b0
812b5pk
812c0
834a5pk
834b5pk
834d0
834d0pk
846e0
846e2
846e5
23
23
23
23
23
23
23
12.5
12.5
12.5
12.5
34.5
34.5
34.5
34.5
46
46
46
Z xfer
strong
strong
strong
medium
medium
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
weak
ZDist
5 mi
5 mi
0
0
5 mi
0
0
5 mi
0
5 mi
0
5 mi
5 mi
0
0
0
2 mi
5 mi
XFMR MVA
Load, MW
LODF
10
10
20
40
40
20
40
10
20
20
40
10
20
40
40
50
50
50
4
8
16
16
32
8
16
4
8
16
16
8
16
16
32
16
20
20
0.2%
0.3%
0.4%
3.4%
1.6%
3.8%
6.7%
1.0%
3.8%
1.3%
6.7%
1.7%
3.0%
8.9%
8.7%
10.3%
9.0%
7.4%
Table 4: Select Sample of Study Results for Distribution Scenario
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 11
34.5 kV and 46 kV Distribution Systems
As with the analysis done for the 12.5 kV system, a conservative transfer impedance value, that of the
’weak’ transmission network, was used in selecting the transfer impedance to be used in the simulations
at 34.5 kV and 46 kV. With this conservative parameter, the simulation results show distribution factors
(LODF) ranging from a low of 1.7% to a high of 10.3%. In all of the cases, the direction of power flow to
the radial lines remained from stations A and B toward stations C and D. In other words, there were no
instances of flow reversal from the distribution system back to the 115 kV transmission system.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 12
Analytical Approach – Sub‐transmission Example
In addition to the distribution circuit loop example described above, the study examined the
performance of systems typically described as ’sub‐transmission.’ The study sought to examine the
interaction and relative magnitude of flows on the 100 kV and above Facilities of the interconnected
transmission system and those of the underlying parallel sub‐transmission facilities. The study
considered a system similar to the one depicted in Figure 4 below. In this simplified depiction of a
portion of a transmission and sub‐transmission system, a 40‐mile transmission line connecting two
sources with transfer impedance between the two sources representing the parallel transmission
network. Each source also supplies a 10‐mile transmission line with a load tap at the mid‐point of the
line, each serving a load of 16 MW. At the end of each of these lines is a step‐down transformer to the
sub‐transmission voltage, where an additional load is served. The two sub‐transmission stations are
connected by a 25‐mile sub‐transmission tie line. Loads and impedances were simulated at the location
shown in Figure 6 of Appendix 2.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 13
Figure 4: Example Radial Systems with Sub‐transmission Loop
Given this example sub‐transmission system, a PSSE model was created to simulate the power flow
characteristics of the system during a contingency outage of the transmission line between stations A
and B. Within this model, parameters were modified to simulate differences in the amount of load
being served, transformer size and the amount of pre‐contingent power flow on the transmission line.
All simulations were performed with a transfer impedance representative of a ‘weak’ transmission
network, which was confirmed as conservative in the distribution system analysis.
Sub‐transmission Model Simulation
Simulations were performed for each sub‐transmission voltage (34.5 kV, 46 kV, 55 kV, and 69 kV) using a
transmission voltage of 115 kV. This analysis identified the potential for power flowing back to the
transmission system only for sub‐transmission voltages of 55 kV and 69 kV. Sensitivity analysis was
performed using higher transmission voltages to confirm that cases modeling a 115 kV transmission
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 14
system yield the most conservative results. Therefore, it was not necessary to perform sensitivity
analysis for sub‐transmission voltages of 34.5 kV and 46 kV for transmission voltages higher than 115 kV.
Table 5 below illustrates the domain of the various parameters that were simulated in this sub‐
transmission circuit loop scenario. A parametric analysis was performed using combinations of variables
shown in each column of Table 5.
Trans KV
Trans Length Sub‐T KV
Sub‐T Length XFMR MVA
Dist Load
Trans MW
% rating
Preload
115
40 miles
34.5
25 miles
40
40
115
46
50
55
60
69
Sensitivity Analyses:
138
40 miles
55
25 miles
50
40
115
161
69
60
135
230
150
220
Table 5: Model Parameters and Sensitivities
Sub‐transmission Model Results
115 kV Transmission System with 34.5‐69 kV Sub‐transmission
The results for cases depicting a 115 kV transmission system voltage and ranges of 34.5 kV to 69 kV sub‐
transmission voltages show line outage distribution factors (LODF) in the range of 9% to slightly higher
than 20%. Several cases show a reversal of power flow in the post‐contingent system such that power
flow is delivered from the sub‐transmission system into the 115 kV BES. The worst case is found in the
69 kV sub‐transmission voltage class. This result is as expected, given that the impedance of the 69 kV
sub‐transmission system is less than the impedances of lower voltage systems. In no instance was a
reversal of power flow observed in sub‐transmission systems rated below 50 kV.
138 kV and 161 kV Transmission Systems with 55‐69 kV Sub‐transmission
The results for cases of 138 kV and 161 kV transmission system voltages supplying sub‐transmission
voltages of 55 kV and 69 kV show LODFs ranging from 9% to 16%. These cases also result in reversal of
power flows in the post‐contingent system such that power flow is delivered from the sub‐transmission
system into the 115 kV BES.
230 kV Transmission System with 55‐69 kV Sub‐transmission
By simulating a higher BES source voltage of 230 kV paired with sub‐transmission voltages of 55 kV and
69 kV, the transformation ratio is sufficiently large to result in a significant increase to the reflected sub‐
transmission system impedance. Therefore, in these cases, LODFs range from 5% to 7%, and these cases
also show no reversal of power flow toward the BES in the post‐contingent system. Table 6 below
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 15
provides a sample of the results of the various simulations that were conducted. All results are provided
in Appendix 3.
Case
T, KV
S‐T, KV
834d25
846e25
855e25
869f25
855e25‐138
855e25‐138’
869f25‐138
869f25‐138’
855e25‐161
855e25‐161’
869f25‐161
869f25‐161’
855e25‐230
855e25‐230’
869f25‐230
869f25‐230’
115
115
115
115
138
138
138
138
161
161
161
161
230
230
230
230
34.5
46
55
69
55
55
69
69
55
55
69
69
55
55
69
69
Trans Pre‐
load, MW
115
114
112
110
114
134
112
132
114
155
113
153
116
219
116
218
XFMR MVA
Load, MW
LODF
40
50
50
60
50
60
60
60
50
60
60
60
50
60
60
60
20
20
20
24
20
20
24
24
20
20
24
24
20
20
24
24
9.4%
13.3%
15.7%
20.3%
11.7%
11.9%
15.6%
15.8%
9.1%
9.2%
12.5%
12.6%
4.9%
5.0%
7.0%
7.0%
Flow Rev
to BES?
Yes
Yes
Yes
Yes
Yes
Yes
Table 6: Select Sample of Study Results for Sub‐transmission Scenario
Step 2 Conclusion
After conducting extensive simulations (included in Appendix 3), the results of Step 2 of this analysis
indicates that 50 kV is the appropriate low voltage loop threshold below which sub‐100 kV loops should
not affect the application of Exclusion E1 of the BES Definition. Simulations of power flows for the cases
modeled in this study show there is no power flow reversal into the BES when circuit loop operating
voltages are below 50 kV. This study also finds, for loop voltages above 50 kV, certain cases result in
power flow toward the BES. Therefore, the study concludes that low voltage circuit loops operated
below 50 kV should not affect the application of Exclusion E1.
As described throughout the preceding section, the scenarios and configurations utilized in this analysis
represent the majority of cases that will be encountered in the industry. The models used in this
analysis establish reasonable bounds and use conservative parameters in the scenarios. However, there
may be actual cases that deviate from these modeled scenarios, and therefore, results could be
somewhat different than the ranges of results from this analysis. Such deviations are expected to be
rare and can be processed through the companion BES Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 16
Study Conclusion
The Project 2010‐17 Standard Drafting Team conducted a two‐step study process to yield a technical
justification for the establishment of a voltage threshold below which sub‐100 kV loops should not affect
the application of Exclusion E1.
All operating entities have guidelines to identify the elements they believe need to be monitored to
facilitate the reliable operation of the interconnected transmission system. Pursuant to these
guidelines, operating entities in each of the eight Regions in North America have identified and monitor
key groupings of the transmission elements that limit the amount of power that can be reliably
transferred across their systems. The objective of Step 1 was to identify the lowest monitored voltage
level on these key element groupings. The lowest monitored line voltage on the major element
groupings provides an indication of the lower limit which operating entities have historically believed
necessary to ensure the reliable operation of the interconnected transmission system.
As a result of studying such regional monitoring levels, Step 1 concluded that 30 kV was a reasonable
voltage level to initiate the sensitivity analysis conducted in Step 2. This is a conservative value as it is
below any of the regional monitoring levels.
Using the conservative value established by Step 1, the Standard Drafting Team conducted extensive
simulations of power flows which demonstrated that there is no power flow reversal into the BES when
circuit loop operating voltages are below 50 kV. Therefore, the study concludes that low voltage circuit
loops operated below 50 kV should not affect the application of Exclusion E1. This analysis provides an
equally effective and efficient alternative to address the Commission’s directives expressed in Order No.
773 and 773‐A.
The scenarios and configurations utilized in this analysis represent the majority of cases that will be
encountered in the industry. The models used in this analysis establish reasonable bounds and use
conservative parameters in the scenarios. However, there may be actual cases that deviate from these
modeled scenarios, and therefore, results could be somewhat different than the ranges of results from
this analysis. Such deviations are expected to be rare and can be processed through the companion BES
Exception Process.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 17
Appendix 1: Regional Elements
PRIVILEGED AND CONFIDENTIAL INFORMATION HAS BEEN REDACTED FROM THIS PUBLIC VERSION
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 18
Appendix 2: One‐Line Diagrams
Note: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Figure 5: Example Radial Systems with Low Voltage Distribution Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 19
Notes: Refer to the notes in Appendix 3 for a description of the symbols in this diagram.
Step‐down transformers from sub‐transmission voltage to distribution voltage were not explicitly
modeled in the simulations.
Figure 6: Example Radial Systems with Sub‐transmission Tie
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 20
Appendix 3: Simulation Results
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
23 kV Base Cases
623a0
10
Strong
15
0
10%/10
10%/10
4.0
4.0
110.7
10.9
6.9
1.1
5.1
11.2
7.2
0.8
4.8
0.003
623a2
10
Strong
15
2
10%/10
10%/10
4.0
4.0
110.7
10.7
6.7
1.4
5.4
10.9
6.9
1.1
5.1
0.002
623a5
10
Strong
15
5
10%/10
10%/10
4.0
4.0
110.7
10.3
6.3
1.7
5.7
10.5
6.5
1.5
5.5
0.002
623a0pk
10
Strong
15
0
10%/10
10%/10
8.0
8.0
111.4
19.0
10.9
5.1
13.1
19.3
11.2
4.8
12.8
0.003
623a2pk
10
Strong
15
2
10%/10
10%/10
8.0
8.0
111.4
18.7
10.7
5.4
13.4
18.9
10.9
5.1
13.1
0.002
623a5pk
10
Strong
15
5
10%/10
10%/10
8.0
8.0
111.5
18.3
10.3
5.7
13.7
18.6
10.5
5.5
13.5
0.003
623b0
10
Strong
15
0
10%/20
10%/20
8.0
8.0
111.1
21.7
13.7
2.3
10.3
22.3
14.2
1.8
9.8
0.005
623b2
10
Strong
15
2
10%/20
10%/20
8.0
8.0
111.2
20.7
12.7
3.3
11.3
21.2
13.2
2.9
10.9
0.004
623b5
10
Strong
15
5
10%/20
10%/20
8.0
8.0
111.3
19.7
11.7
4.3
12.3
20.1
12.1
4.0
12.0
0.004
623b0pk
10
Strong
15
0
10%/20
10%/20
16.0
16.0
112.6
37.8
21.7
10.3
26.3
38.3
22.3
9.7
25.8
0.004
623b2pk
10
Strong
15
2
10%/20
10%/20
16.0
16.0
112.7
36.7
20.7
11.3
27.3
37.2
21.2
10.9
26.9
0.004
623b5pk
10
Strong
15
5
10%/20
10%/20
16.0
16.0
112.8
35.7
19.7
12.3
28.4
36.1
20.1
12.0
28.0
0.004
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 21
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
623c0
10
Strong
15
0
10%/40
10%/40
16.0
16.0
112.2
42.7
26.6
5.4
21.4
43.7
27.7
4.3
20.3
0.009
623c2
10
Strong
15
2
10%/40
10%/40
16.0
16.0
112.5
39.6
23.6
8.4
24.4
40.4
24.4
7.7
23.7
0.007
623c5
10
Strong
15
5
10%/40
10%/40
16.0
16.0
112.7
37.3
21.3
10.8
26.8
37.8
21.8
10.3
26.3
0.004
LODF
623c0pk
10
Strong
15
0
10%/40
10%/40
32.0
32.0
115.1
74.9
42.8
21.2
53.3
76.0
43.9
20.2
52.2
0.010
623c2pk
10
Strong
15
2
10%/40
10%/40
32.0
32.0
115.4
71.8
39.7
24.3
56.4
72.6
40.5
23.6
55.6
0.007
623c5pk
10
Strong
15
5
10%/40
10%/40
32.0
32.0
115.6
69.4
37.4
26.7
58.8
70.0
37.9
26.2
58.3
0.005
723a0
10
Medium
15
0
10%/10
10%/10
4.0
4.0
108.3
10.9
6.9
1.1
5.1
11.9
7.9
0.1
4.1
0.009
723a2
10
Medium
15
2
10%/10
10%/10
4.0
4.0
108.3
10.6
6.6
1.4
5.4
11.5
7.5
0.5
4.5
0.008
723a5
10
Medium
15
5
10%/10
10%/10
4.0
4.0
108.4
10.3
6.3
1.8
5.8
11.1
7.1
1.0
5.0
0.007
723a0pk
10
Medium
15
0
10%/10
10%/10
8.0
8.0
110.4
18.9
10.9
5.1
13.1
20.0
12.0
4.0
12.1
0.010
723a2pk
10
Medium
15
2
10%/10
10%/10
8.0
8.0
110.5
18.6
10.6
5.4
13.4
19.6
11.6
4.4
12.5
0.009
723a5pk
10
Medium
15
5
10%/10
10%/10
8.0
8.0
110.6
18.3
10.3
5.7
13.7
19.1
11.1
4.9
12.9
0.007
723b0
10
Medium
15
0
10%/20
10%/20
8.0
8.0
109.7
21.6
13.6
2.4
10.4
23.6
15.6
0.4
8.4
0.018
723b2
10
Medium
15
2
10%/20
10%/20
8.0
8.0
110.0
20.6
12.6
3.4
11.4
22.3
14.3
1.7
9.8
0.015
723b5
10
Medium
15
5
10%/20
10%/20
8.0
8.0
110.2
19.7
11.7
4.4
12.4
21.0
13.0
3.1
11.1
0.012
723b0pk
10
Medium
15
0
10%/20
10%/20
16.0
16.0
114.0
37.8
21.8
10.2
26.3
39.9
23.8
8.2
24.2
0.018
723b2pk
10
Medium
15
2
10%/20
10%/20
16.0
16.0
114.3
36.8
20.8
11.3
27.3
38.5
22.5
9.6
25.6
0.015
723b5pk
10
Medium
15
5
10%/20
10%/20
16.0
16.0
114.5
35.8
19.8
12.3
28.3
37.2
21.1
10.9
27.0
0.012
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 22
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
723c0
10
Medium
15
0
10%/40
10%/40
16.0
16.0
112.6
42.7
26.7
5.3
21.3
46.5
31.4
1.6
17.6
0.034
723c2
10
Medium
15
2
10%/40
10%/40
16.0
16.0
113.5
39.7
23.7
8.4
24.4
42.4
26.4
5.7
21.7
0.024
723c5
10
Medium
15
5
10%/40
10%/40
16.0
16.0
114.1
37.4
21.4
10.7
26.7
39.3
23.3
8.8
24.8
0.017
723c0pk
10
Medium
15
0
10%/40
10%/40
32.0
32.0
121.2
75.5
43.4
20.7
52.7
79.5
47.4
16.7
48.7
0.033
723c2pk
10
Medium
15
2
10%/40
10%/40
32.0
32.0
122.0
72.2
40.1
23.9
55.9
75.2
43.1
21.1
53.1
0.025
723c5pk
10
Medium
15
5
10%/40
10%/40
32.0
32.0
122.7
69.8
37.7
26.4
58.5
71.8
39.7
24.4
56.5
0.016
823a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
823a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
823a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.4
10.2
62.0
1.8
5.8
11.9
7.9
0.2
4.2
0.016
823a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
823a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.6
12.6
3.5
11.5
0.018
823a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.8
18.3
10.3
5.7
13.8
20.0
12.0
4.0
12.1
0.015
823b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
823b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.8
20.6
12.6
3.4
11.4
24.0
16.0
0.1
8.1
0.031
823b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
109.2
19.6
11.6
4.4
12.4
22.3
14.3
1.8
9.8
0.025
823b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
823b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.7
36.9
20.8
11.2
27.2
40.4
24.4
7.7
23.7
0.030
823b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
116.2
35.9
19.8
12.2
28.2
38.7
22.7
9.4
25.5
0.024
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 23
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
823c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
823c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
114.4
39.7
23.7
8.3
24.3
45.4
29.3
2.8
18.8
0.050
823c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
115.5
37.4
21.4
10.6
26.7
41.4
25.4
6.8
22.8
0.035
823c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
823c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
128.2
72.7
40.6
23.5
55.6
78.9
48.6
17.4
49.5
0.048
823c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
129.3
70.1
38.0
26.1
58.2
74.5
42.4
21.8
53.9
0.034
Sensitivity to Length of Lines 1‐4
723a0_30
10
Medium
30
0
10%/10
10%/10
4.0
4.0
108.3
10.8
6.8
1.2
5.2
11.8
7.8
0.2
4.2
0.009
723a2_30
10
Medium
30
2
10%/10
10%/10
4.0
4.0
108.4
10.5
6.5
1.5
5.5
11.4
7.4
0.6
4.6
0.008
723a5_30
10
Medium
30
5
10%/10
10%/10
4.0
4.0
108.5
10.2
6.2
1.8
5.8
11.0
7.0
1.0
5.0
0.007
Selected 34.5 kV cases
834a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
834a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.1
10.7
6.7
1.3
5.3
12.7
8.7
‐0.7
3.3
0.019
834a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.2
10.5
6.5
1.5
5.5
12.4
8.4
‐0.4
3.6
0.018
834a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
834a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.6
18.8
10.8
5.2
13.3
20.8
12.8
3.2
11.2
0.018
834a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
109.7
18.6
10.6
5.4
13.4
20.5
12.5
3.5
11.5
0.017
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
834b0
10
Weak
15
0
10%/20
10%/20
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 24
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
834b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
108.6
21.1
13.1
2.9
10.9
24.8
16.8
‐0.7
7.3
0.034
834b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
108.9
20.5
12.5
3.5
11.5
23.8
15.8
0.3
8.3
0.030
LODF
834b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
834b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
115.5
37.4
21.4
10.7
26.7
41.3
25.3
6.8
22.8
0.034
834b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
115.8
36.8
20.7
11.3
27.3
40.3
24.2
7.8
23.9
0.030
834c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
834c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
113.8
41.2
25.2
6.9
22.9
47.8
31.7
0.4
16.4
0.058
834c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
114.6
39.5
23.5
8.5
24.6
45.0
29.0
3.2
19.2
0.048
834c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
834c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
127.5
74.2
42.1
21.9
54.0
81.5
49.4
14.7
46.8
0.057
834c5pk
10
Weak
15
5
10%/40
10%/40
32.0
32.0
128.3
72.4
40.3
23.8
55.8
78.5
46.4
17.9
49.9
0.048
834d0
10
Weak
15
0
7%/40
7%/40
16.0
16.0
111.6
46.3
30.3
1.7
17.7
56.2
40.1
‐8.1
7.9
0.089
834d2
10
Weak
15
2
7%/40
7%/40
16.0
16.0
112.8
43.6
27.6
4.4
20.4
51.8
35.8
‐3.6
12.4
0.073
834d5
10
Weak
15
5
7%/40
7%/40
16.0
16.0
113.9
41.1
25.1
7.0
23.0
47.6
31.6
0.6
16.6
0.057
834d0pk
10
Weak
15
0
7%/40
7%/40
32.0
32.0
124.9
80.0
47.9
16.2
48.2
90.9
58.8
5.3
37.3
0.087
834d2pk
10
Weak
15
2
7%/40
7%/40
32.0
32.0
126.3
77.0
44.9
19.2
51.2
86.1
54.0
10.2
42.2
0.072
834d5pk
10
Weak
15
5
7%/40
7%/40
32.0
32.0
127.5
74.2
42.1
22.0
54.1
81.4
49.3
15.0
47.0
0.056
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 25
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
LODF
Selected 12.47 kV cases
812a0
10
Weak
15
0
10%/10
10%/10
4.0
4.0
106.1
10.8
6.8
1.2
5.2
12.9
8.9
‐0.9
3.1
0.020
812a2
10
Weak
15
2
10%/10
10%/10
4.0
4.0
106.4
10.1
6.1
1.9
5.9
11.6
7.6
0.4
4.4
0.014
812a5
10
Weak
15
5
10%/10
10%/10
4.0
4.0
106.7
9.4
5.4
2.6
6.6
10.5
6.5
1.5
5.5
0.010
812a0pk
10
Weak
15
0
10%/10
10%/10
8.0
8.0
109.6
18.9
10.9
5.1
13.1
21.1
13.0
3.0
11.0
0.020
812a2pk
10
Weak
15
2
10%/10
10%/10
8.0
8.0
109.9
18.1
10.1
5.9
13.9
19.7
11.7
4.3
12.4
0.015
812a5pk
10
Weak
15
5
10%/10
10%/10
8.0
8.0
110.2
17.5
9.5
6.5
14.5
18.6
10.6
5.5
13.5
0.010
812b0
10
Weak
15
0
10%/20
10%/20
8.0
8.0
108.4
21.5
13.5
2.5
10.5
25.6
17.6
‐1.6
6.4
0.038
812b2
10
Weak
15
2
10%/20
10%/20
8.0
8.0
109.4
19.2
11.2
4.8
12.8
21.7
13.6
2.5
10.5
0.023
812b5
10
Weak
15
5
10%/20
10%/20
8.0
8.0
110.0
17.9
9.9
6.1
14.1
19.4
11.4
4.7
12.7
0.014
812b0pk
10
Weak
15
0
10%/20
10%/20
16.0
16.0
115.3
37.9
21.9
10.2
26.2
42.2
26.1
5.9
21.9
0.037
812b2pk
10
Weak
15
2
10%/20
10%/20
16.0
16.0
116.4
35.4
19.4
12.6
28.6
38.0
22.0
10.2
26.2
0.022
812b5pk
10
Weak
15
5
10%/20
10%/20
16.0
16.0
117.0
34.1
18.0
14.0
30.0
35.6
19.6
12.6
28.6
0.013
812c0
10
Weak
15
0
10%/40
10%/40
16.0
16.0
113.1
42.7
26.7
5.3
21.3
50.3
34.3
‐2.3
13.7
0.067
812c2
10
Weak
15
2
10%/40
10%/40
16.0
16.0
115.9
36.6
20.6
11.5
27.5
40.0
24.0
8.3
24.3
0.029
812c5
10
Weak
15
5
10%/40
10%/40
16.0
16.0
116.8
34.4
18.4
13.7
29.7
36.2
20.2
12.0
28.0
0.015
812c0pk
10
Weak
15
0
10%/40
10%/40
32.0
32.0
126.7
76.0
43.9
20.2
52.2
84.4
52.3
11.8
43.8
0.066
812c2pk
10
Weak
15
2
10%/40
10%/40
32.0
32.0
129.7
69.2
37.1
27.1
59.1
73.0
40.9
23.5
55.5
0.029
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 26
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
10
Weak
15
5
10%/40
10%/40
32.0
32.0
130.8
66.7
34.7
29.4
61.5
68.8
36.7
27.6
59.6
0.016
846e0
10
Weak
15
0
10%/40
7%/50
16.0
20.0
112.1
53.1
37.1
2.9
18.9
64.7
48.7
‐8.6
7.4
0.103
846e2
10
Weak
15
2
10%/40
7%/50
16.0
20.0
113.2
50.7
34.7
5.3
21.3
60.9
44.8
‐4.7
11.3
0.090
846e5
10
Weak
15
5
10%/40
7%/50
16.0
20.0
114.3
48.2
32.1
7.9
24.0
56.7
40.7
‐0.4
15.6
0.074
669f25
40
Strong
20
25
10%/40
7%/60
16.0
24.0
114.0
76.0
59.8
‐10.8
5.2
79.6
63.4
‐14.2
1.8
0.032
769f25
40
Medium
20
25
10%/40
7%/60
16.0
24.0
111.7
75.3
59.1
‐10.1
5.9
87.3
71.0
‐21.2
‐5.2
0.107
869f25
40
Weak
20
25
10%/40
7%/60
16.0
24.0
109.8
74.7
58.5
‐9.6
6.4
97.0
80.6
‐30.0
‐14.0
0.203
812c5pk
LODF
Selected 46 kV cases
Sub‐transmission cases
115‐69 kV
115‐55 kV
655e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
114.5
62.1
46.0
‐5.0
11.0
64.8
48.7
‐7.5
8.5
0.024
755e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
113.3
61.8
45.7
‐4.8
11.2
70.9
54.8
‐13.0
3.0
0.080
855e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
112.1
61.5
45.4
‐4.5
11.5
79.1
62.9
‐20.2
‐4.2
0.157
855f25
115‐46 kV
646e25
40
Strong
20
25
10%/40
7%/50
16.0
20.0
115.0
57.3
41.2
‐0.2
15.8
59.5
43.4
‐2.1
13.9
0.019
746e25
40
Medium
20
25
10%/40
7%/50
16.0
20.0
114.6
57.2
41.2
‐0.1
15.9
64.9
48.8
‐6.8
9.2
0.067
846e25
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.2
57.2
41.1
0.0
16.0
72.4
56.2
‐13.1
2.9
0.133
40
Strong
20
25
10%/40
7%/40
16.0
16.0
115.3
46.2
30.2
2.6
18.7
47.7
31.7
1.4
17.4
0.013
115‐34.5 kV
634d25
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 27
‐‐‐‐‐‐‐‐‐‐‐‐ HV Line "L" in‐service ‐‐‐‐‐‐‐‐‐‐‐‐
Case
‐‐ HV Line "L" out‐of‐service ‐‐
ZL
Ztr
Zln1‐4
Zdist
ZT1, ZT‐4
ZT2, ZT3
L1, L4
L2, L3
PL
Pln1
Pln2
Pln3
Pln4
Pln1'
Pln2'
Pln3'
Pln4'
(mi.)
(mi.)
(total mi.)
(mi.)
(Z/MVA)
(Z/MVA)
(MW)
(MW)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
(MVA)
734d25
40
Medium
20
25
10%/40
7%/40
16.0
16.0
115.4
46.3
30.2
2.6
18.6
51.5
35.5
‐1.9
14.1
0.045
834d25
40
Weak
20
25
10%/40
7%/40
16.0
16.0
115.5
46.3
30.2
2.6
18.6
57.1
41.0
‐6.4
9.6
0.094
869f25‐138
40
Weak
20
25
10%/40
7%/60
16.0
24.0
112.0
66.5
50.4
‐1.8
14.2
84.0
67.9
‐18.3
‐2.3
0.156
869f25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
131.9
71.1
55.0
‐6.3
9.8
92.0
75.8
‐25.6
‐9.6
0.158
LODF
138‐69 kV
138‐55 kV
855e25‐138
40
Weak
20
25
10%/40
7%/50
16.0
20.0
113.5
55.1
39.0
1.5
17.5
68.4
52.3
‐10.8
5.2
0.117
855e25‐138'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
134.0
58.5
42.4
‐1.7
14.3
74.4
58.3
‐16.2
‐0.2
0.119
869f25‐161
40
Weak
20
25
10%/40
7%/60
16.0
24.0
113.2
60.7
44.7
3.7
19.7
74.8
58.8
‐9.8
6.2
0.125
869f25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
153.0
68.0
52.0
‐3.3
12.7
87.3
71.2
‐21.4
‐5.4
0.126
855e25‐161
40
Weak
20
25
10%/40
7%/50
16.0
20.0
114.1
50.7
34.7
5.6
21.6
61.1
45.1
‐4.2
11.8
0.091
855e25‐161'
40
Weak
20
25
10%/40
7%/60
16.0
20.0
154.8
56.0
40.0
0.6
16.6
70.3
54.3
‐12.6
3.4
0.092
869f25‐230
40
Weak
20
25
10%/40
7%/60
16.0
24.0
116.3
51.3
35.3
12.8
28.8
59.4
43.3
5.0
21.0
0.070
869f25‐230'
40
Weak
20
25
10%/40
7%/60
16.0
24.0
217.7
61.2
45.2
3.2
19.2
76.5
60.4
‐11.4
4.7
0.070
855e25‐230
40
Weak
20
25
10%/40
7%/50
16.0
20.0
116.1
43.8
27.8
12.3
28.3
49.5
33.5
6.7
22.8
0.049
855e25‐230'
40
Weak
20
25
10%/40
7%/50
16.0
20.0
218.7
50.8
34.8
5.6
21.6
61.7
45.7
‐4.7
11.3
0.050
161‐69 kV
161‐55 kV
230‐69 kV
230‐55 kV
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 28
Notes:
The following notes provide information to understand the meaning of each column heading and
underlying assumptions used in the analysis. See also the one‐line diagrams in Figures 5 and 6 of
Appendix 2 for additional information.
ZL
The table provides the length of line “L” in miles to provide a high‐level, qualitative understanding of the
line impedance. The line impedance (ZL) is the length of the line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
230
954 ACSR
25.20’
0.100 + j0.786
0.000189 + J 0.00149
954 ACSR
20’ H‐frame
16’ H‐frame
161
20.16’
0.100 + j0.759
0.000384 + j 0.00293
138
795 ACSR
13’ H‐frame
16.38’
0.117 + j0.738
0.000615 + j 0.00388
115
795 ACSR
11’ H‐frame
13.86’
0.117 + j0.718
0.000886 + j 0.00543
Ztr
The transfer impedance (Ztr) represents the impedance of the system in parallel with the subsystem
under study. Analysis was performed for three levels of parallel transfer impedance which have been
characterized as strong, medium, and weak. The strong system has relatively low impedance and thus
will pick up more power flow when line “L” is tripped. The weak system has relatively high impedance
and thus will pick up less power flow when line “L” is tripped. The medium system has a mid‐range
impedance value. The actual values of the transfer impedance vary between the distribution cases and
the sub‐transmission cases.
Ztr in distribution cases (p.u.)
Ztr in sub‐transmission cases (p.u.)
Strong
0.00089 + j 0.00543
0.00354 + j 0.0217
Medium
0.00319 + j 0.0195
0.0128 + j 0.0782
Weak
0.00664 + j 0.0407
0.0266 + j 0.163
Zln1‐4
The table provides the total length of lines “ln1” through “ln4.” In all simulations these four lines have
equal length. The total length in miles provides a high‐level, qualitative understanding of the line
impedance. The line impedances are the length of each line in miles times the per mile impedance.
Assumptions used in determining the per mile impedance are the same as provided above for line “L.”
Zdist
The table provides the length of the line in miles to provide a high‐level, qualitative understanding of the
line impedance. The impedance of the distribution system or sub‐transmission system (Zdist) is the length
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 29
of the distribution tie or sub‐transmission line in miles times the per mile impedance. A value of zero
miles is used when the distribution tie is a solid bus tie. Assumptions used in determining the per mile
impedance are as follows:
Impedance
Impedance
Voltage (kV)
Conductor
Phase Spacing
GMD
(Ω/mile)
(p.u./mile)
69
636 ACSR
6’ Horizontal
7.56’
0.145 + j0.657
0.00305 + j 0.0138
55
556 ACSR
6’ Horizontal
7.56’
0.168 + j0.677
0.00555 + j 0.0224
46
477 ACSR
6’ Triangular
6.00’
0.193 + j0.647
0.00913 + j 0.0306
34.5
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0162 + j 0.0503
23
477 ACSR
4’ Triangular
4.00’
0.193 + j0.598
0.0365 + j 0.113
12.47
336 ACSR
2’ Horizontal
2.52’
0.274 + j0.563
0.176 + j 0.362
ZT1‐4
The transformer impedance is reported as percent impedance on the transformer MVA base. Each
transformer has three ratings: OA (oil and air), FA (forced air – i.e., fans), and FOA (forced oil and air –
i.e., pumps and fans). The transformer MVA base rating is the OA rating. The FA rating is 133% of the OA
rating and the FOA rating is 167% of the OA rating (e.g., a 20 MVA transformer has a 20 MVA OA rating,
26.7 MVA FA rating, and 33.3 MVA FOA rating, typically identified as a nameplate of 20/26.7/33.3 MVA).
The transformer impedance and rating for each voltage level are based on typical values. Distribution
transformer impedance is generally higher to limit current on the distribution equipment. Secondary
current typically is not a concern on sub‐transmission transformers, so impedance is typically lower to
limit reactive power losses and voltage drop.
L1, L2, L3, L4
The transformer load is based on the transformer OA rating. Transformers are loaded at 80 percent of
the transformer base MVA in the simulations modeling a peak system load condition. The substations
modeled have two transformers, with each transformer able to supply the total station load. Thus, if one
transformer is forced out‐of‐service, the load on the remaining transformer will be 160 percent of its
base rating, which is approximately equal to its FOA rating.
Transformers are loaded at 40 percent of the transformer base MVA in the simulations modeling a light
system load condition.
HV Line "L" in‐service: PL, Pln1, , Pln2, Pln3, Pln4
The loading on each line, with all lines in service, is listed in MVA. The loading on line “L” is the power
that is redistributed between the parallel transmission system and the distribution or sub‐transmission
system when line “L” is taken out of service.
HV Line "L" out‐of‐service: Pln1, , Pln2, Pln3, Pln4
The loading on each line, with line “L” out‐of‐service, is listed in MVA.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 30
LODF
The Line Outage Distribution Factor (LODF) is the fraction of the load on line “L” that is picked up on the
distribution or sub‐transmission system. This information is included for illustrative purposes to
understand the analysis, but was not used in identifying the voltage threshold for Exclusion E1.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 31
Appendix 4: Summary of Loop Flow Issue Through Systems <50 kV
In the course of developing ‘real‐world’ scenarios for the analysis of potential sub‐100 kV loop flows, the
Standard Drafting Team found that the industry has employed various measures to minimize the subject
loop flows. Some of these methods that were found to be applied by entities on sub‐100 kV loop
systems are described below. However, it is important to note that the presence of the equipment in
the following examples does not remove or lessen an entity’s obligations associated with the bright‐line
application of the Bulk Electric System (BES) definition.
Sustained power flow through substation power transformers and low voltage loops is generally
undesirable and, in some instances injurious. For this reason, power system engineers typically address
this issue in their design, operating, and planning criteria and apply methods to prevent this condition
from occurring. The high impedance of transformers and low voltage elements inherently prevent
excessive flow, but in many instances this flow can exceed ratings of equipment. For these reasons
entities develop control schemes, add relaying, and provide operational and planning guidelines to
prevent this loop flow. Figure 7 depicts two systems that could provide a possible loop flow across the
low voltage system and back up to the high voltage system. The loop flow in these diagrams is increased
when the breaker on the high voltage side (breaker B) is opened.
The diagrams presented below depict a generic power system. The higher voltage and lower voltage
circuit breakers and bus arrangements will, in practice, vary (i.e., straight bus, half‐breaker, ring bus,
breaker‐and‐a‐half, etc.), but the concepts remain the same.
Specifically, Figure 7, shown below, depicts segments of an electrical power system. They consist of a
greater than 100 kV system and a sub‐100 kV system. Figure 7 depicts the power flow through the
electrical system under the condition that all circuit breakers are closed (normal condition). In the event
that circuit breaker B opens (i.e., manually, supervisory control, or protective device operation) and (1)
and either of the sub‐100 kV line circuit breakers (A or C) or (2) either of the low‐side transformer circuit
breakers (D or F) or (3) the low‐side bus tie circuit breaker (E) does not open, a condition could occur
where some amount of flow will occur through the sub‐100 kV system to the greater than 100 kV
system. This flow is severely limited by the high impedance of the two transformers in series and the
sub‐100 kV system impedance. This condition, however, may be deemed undesirable from an
equipment standpoint and precautions may be taken to prevent it. Subsequent sections of this appendix
show some of the physical schemes that entities can employ in this regard.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 32
Figure 7. Summary of Loop Flow
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 33
Interlocked Control Schemes
Interlocking control schemes can be used to prevent low voltage loop flow. One method to preclude
sustained power flow from the lower voltage to the higher voltage portion of the system is to include
control system interlocks which will cross‐trip certain circuit breaker(s) when other specified circuit
breakers are opened. This condition is generally rare since bus designs and protective relay system
operations generally do not result in this condition occurring. Operational guidelines usually instruct
personnel to avoid the use of the interlocking schemes during normal or planned switching. However,
unplanned actions can cause breakers to open and result in the desirable operation of the interlocking
schemes. This method, therefore, is considered to be conservative but, never‐the‐less, it is applied in
some instances.
Figure 8 below shows how an interlock scheme would function to prevent low voltage loop flow. When
the high side breaker (breaker B) is opened, the low side breaker (breaker E) is also opened. This action
prevents low side loop flow. The interlocking scheme could be applied in various combinations and the
figure below is a simplified illustration of such a scheme.
Figure 8. Interlocking Schemes
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 34
Reverse Power Schemes
Protection schemes can also be deployed to prevent sustained loop flows through the sub‐100 kV
system. Reverse power applications are one example of a protection scheme that prevents sustained
undesirable low voltage loop flow. In some instances, protective devices will preclude sustained loop
flows due to their settings and in other instances protective schemes are specifically applied to preclude
this undesirable operating condition.
Figure 9 below shows how a reverse power scheme would function to prevent sub‐100 kV loop flow.
When the high side breaker (breaker B) is opened, current may flow from the high voltage side (breaker
A) through the low voltage bus and back to the high voltage side (breaker C). A relay on breaker F is
applied to sense the reverse flow (relay shown in yellow in the diagram) and will operate if this flow
continues (relay shown in red in the diagram). When the reverse power relay operates it will trip
breaker F. This action prevents reverse power flow through the transformer and low voltage loop flow.
The reverse power scheme is set to sense a minimum amount of power flowing in a reverse direction
and is usually set much less than the transformer rating. The figure below is a simplified illustration of a
reverse power scheme.
Figure 9. Reverse Power Schemes
Transformer Overcurrent Limitations
Transformer overcurrent protection schemes can also be deployed to prevent sustained loop flows
through the sub‐100 kV system. Figure 10 below shows how a transformer overcurrent scheme would
function to prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current
may flow from the high voltage side (breaker A) through the low voltage bus and back to the high
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 35
voltage side (breaker C). The relay on the transformer and breaker D is applied to protect the
transformer from excessive overloads and faults on the low voltage system. If a fault occurs or the
transformer is over‐loaded then the relay on breaker D will sense this excessive flow (relay shown in
yellow in the diagram) and will operate if this flow continues (relay shown in red in the diagram). When
the transformer overcurrent relay operates it will trip breaker D. This action unloads the transformer in
question and prevents low voltage loop flow. The transformer overcurrent relay is typically set to allow
the transformer to be loaded to the emergency rating of the transformer plus a small safety margin.
The figure below is a simplified illustration of a transformer overcurrent scheme.
Figure 10. Transformer Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 36
Feeder Overcurrent Limitations
Feeder overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 11 below shows how a feeder overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage feeder, through a feeder tie, and back to the
high voltage side (breaker C). The relay on the feeder and breaker G is applied to protect the feeder
from excessive overloads and faults on the low voltage feeder. If a fault occurs or the feeder is over
loaded, the relay on breaker G will sense this excessive flow (relay shown in yellow in the diagram) and
will operate if this flow continues (relay shown in red in the diagram). When the feeder overcurrent
relay operates it will trip breaker G. This action opens the feeder breaker and prevents low voltage loop
flow. The feeder overcurrent relay is typically set to allow the feeder to be loaded to the emergency
rating of the feeder rating plus a small safety margin. The figure below is a simplified illustration of a
feeder overcurrent power scheme.
Figure 11. Feeder Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 37
Bus Tie Overcurrent Limitations
Bus tie overcurrent protection schemes can also be deployed to prevent sustained loop flows through
the sub‐100 kV system. Figure 12 below shows how a bus tie overcurrent scheme would function to
prevent sub‐100 kV loop flow. When the high side breaker (breaker B) is opened, current may flow from
the high voltage side (breaker A) through the low voltage bus and back to the high voltage side (breaker
C). The relay on the bus tie and breaker E is applied to protect the bus from excessive overloads and
faults on the low voltage bus(ses). If a fault occurs or the bus is over loaded, then the overcurrent relay
on breaker E will sense this excessive flow (relay shown in yellow in the diagram) and will operate if this
flow continues (relay shown in red in the diagram). When the bus tie overcurrent relay operates, it will
trip breaker E. This action opens the bus tie breaker and prevents sustained low voltage loop flow. The
bus tie overcurrent relay is typically set to allow the bus to be loaded to the emergency rating plus a
small safety margin. The figure below is a simplified illustration of a bus tie overcurrent power scheme.
A
C
C
A
B
B
> 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
D
D
F
R
F
R
E
E
< 100kV
Loop Flow
Load
Load
Load
BUS TIE (Outage)
Load
Bus Tie Operate
Figure 12. Bus Tie Overcurrent Limitations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 38
Custom Protection and Control Schemes
Custom protection and control schemes may also be deployed to prevent loop flows through the sub‐
100 kV system. Figure 13 below shows how such schemes would function to prevent sub‐100 kV loop
flow. When the greater than 100 kV line 1 breakers (breakers D and G) open, current may flow from the
high voltage side (breaker E) through the low voltage bus and back to the high voltage side (breaker H).
The custom scheme implemented at the substation will trip or run back generation to prevent over
loads and sustained loop flows on the low voltage system.
A
Gen 1
B
C
Line 2
F
I
D
Line 1
G
J
E
A
Gen 1
H
Gen 2
B
C
Line 2
F
I
D
Line 1
G
J
E
H
Gen 2
> 100kV
< 100kV
> 100kV
< 100kV
Legend
Current Flow
Open Breaker
Relay Operate R
Load
Loop Flow
Load
Load
Line Outage
Load
Custom Scheme Operates to Reduce Gen
Figure 13. Custom Scheme Operations
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 39
Appendix 4 Summary
The issues and methods described in Appendix 4 are reflective of why, in most instances, conditions of
sustained loop flows through sub‐100 kV systems are alleviated. When the low voltage is much less
than 100 kV, the design considerations shown above become even more pertinent and preventative
methods are employed; BES reliability is not the main concern, protecting the equipment from physical
damage is the primary concern. In the vast majority of cases, robust planning and operating criteria and
procedures will alleviate any concerns regarding sustained loop flows.
Project 2010‐17 Definition of BES – Phase 2 SDT Report on sub‐100 kV Looping Facilities
Page 40
E-mail completed form to:
[email protected]
Standards Authorization Request
Form
Title of Proposed Standard
definition
NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System
Request Date
December 2, 2011
SAR Type
SAR Requester Information
(Check all that apply)
Name: Project 2010-17 Definition of Bulk Electric
System (BES) SDT
Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT Chair
Telephone: (813) 207-7994
Fax: (813) 289-5646
E-mail: [email protected]
New Standard
X
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?)
This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Purpose or Goal (How does this request propose to address the problem described above?)
Research possible revisions to the definition of BES (Phase 2) to address the issues identified through
Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition encompasses all
Elements necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
Standards Authorization Request
SAR Information
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and
technically sound definition of the Bulk Electric System (BES).
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?)
Revise the BES definition to identify the appropriate electrical components necessary for the reliable
operation of the interconnected transmission network.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Collect and analyze information needed to support revisions to the definition of Bulk Electric System
(BES) developed in Phase 1 of this project to provide a technically justifiable definition that identifies
the appropriate electrical components necessary for the reliable operation of the interconnected
transmission network. The definition development may include other improvements to the definition
as deemed appropriate by the drafting team, with the consensus of stakeholders, consistent with
establishing a high quality and technically sound definition of the BES.
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.)
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.
•
•
•
•
Form
Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources necessary for the reliable operation of the Bulk Electric System (BES)
The NERC Board of Trustees approved BES Phase 1 definition does not encompass a contiguous
BES - Determine if there is a need to change this position
Determine if there is a technical justification to revise the current 100 kV bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
2
Standards Authorization Request
SAR Information
network under certain conditions and if so, what the maximum allowable flow and duration
should be
Provide improved clarity to the following:
•
•
•
The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources
•
The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution
Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the BES.
Based on the potential revisions to the definition of the BES and an analysis of the application of, and
the results from, the exception process, the drafting team will review and if necessary propose
revisions to the ‘Technical Principles’ associated with the Rules of Procedure Exception Process to
ensure consistency in the application of the definition and the exception process.
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
This section is not applicable as the SAR is for a definition which is about Elements, Applicability of
entities is covered in Section 4 of each Reliability Standard.
Form
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.
3
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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.
Administers the transmission tariff and provides transmission
Transmission
services under applicable transmission service agreements (e.g., the
Service Provider
pro forma tariff).
Form
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
4
Standards Authorization Request
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
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 box for all that apply.)
X
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.
X
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.
X
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.
X
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
X
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
X
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
X
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
X
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Form
5
Standards Authorization Request
Applicable Reliability Principles (Check box for all that apply.)
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Form
Explanation
6
Standards Authorization Request
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Form
7
Standards Announcement
Project 2010-17 Definition of Bulk Electric System - Phase 2
A Final Ballot is now open through November 18, 2013
Now Available
A final ballot for Phase 2 of the Definition of Bulk Electric System is open through 8 p.m. Eastern on
Monday, November 18, 2013.
The drafting team considered stakeholder comments from the comment period and ballot that ended
on October 29, 2013 and made no changes to the definition or implementation plan. The drafting
team’s consideration of comments, along with clean and redline versions of the definition and other
supporting documents, have been posted on the project page. The redline of the definition reflects
changes to the development roadmap (development steps completed and next steps) only.
Background information and documents for this project can be found on the project page.
Instructions for Balloting
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
definition by clicking here.
Next Steps
Voting results for the definition will be posted and announced after the ballot window closes. If
approved, the definition 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.
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
Standards Announcement
Project 2010-17 Definition of Bulk Electric System | November 8, 2013
2
Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Phase 2
Final Ballot Results
Now Available
A final ballot for Phase 2 of the Definition of Bulk Electric System concluded at 8 p.m. Eastern on
Monday, November 18, 2013.
The definition 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 additional ballot.
Approval
Quorum: 81.68%
Approval: 74.34%
Background information for this project can be found on the project page.
Next Steps
The definition 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
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Project 2010-17 Definition of BES - Phase 2 Final Ballot
Ballot Name:
November
Password
Ballot Period: 11/8/2013 - 11/18/2013
Log in
Ballot Type: Final Ballot
Register
Total # Votes: 321
Total Ballot Pool: 393
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Home Page
Quorum: 81.68 % The Quorum has been reached
Weighted Segment
74.34 %
Vote:
Ballot Results:
A quorum was reached and there were sufficient affirmative votes for approval
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
104
1
55
0.724
21
0.276
0
7
21
8
0.5
5
0.5
0
0
0
3
0
90
1
46
0.697
20
0.303
0
8
16
36
1
19
0.704
8
0.296
0
2
7
88
1
48
0.706
20
0.294
0
5
15
51
1
26
0.65
14
0.35
0
2
9
2
0.1
0
0
1
0.1
0
0
1
2
0.1
1
0.1
0
0
0
0
1
4
0.2
2
0.2
0
0
0
0
2
8
0.8
7
0.7
1
0.1
0
0
0
393
6.7
209
4.981
85
1.719
0
27
72
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
NERC Standards
Segment
Organization
Member
1
1
1
Ameren Services
American Transmission Company, LLC
Arizona Public Service Co.
Eric Scott
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
1
1
1
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Big Rivers Electric Corp.
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Chris Bradley
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
1
Central Electric Power Cooperative
Michael B Bax
1
1
Kevin J Lyons
Joseph Turano Jr.
1
Central Iowa 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.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
El Paso Electric Company
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
1
KAMO Electric Cooperative
Walter Kenyon
1
1
1
1
1
1
1
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
Jennifer Flandermeyer
Stanley T Rzad
Larry E Watt
John Chin
Doug Bantam
Robert Ganley
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Nazra S Gladu
Danny Dees
Allan Long
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Chang G Choi
Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Michael S Crowley
Douglas E. Hils
Amber Anderson
Dennis Malone
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Jason Snodgrass
Gordon Pietsch
Bob Solomon
Ballot
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Ajay Garg
Martin Boisvert
Molly Devine
Abstain
Abstain
Affirmative
Michael Moltane
Affirmative
Jim D Cyrulewski
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
NERC
Notes
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
NERC Standards
1
1
1
MidAmerican Energy Co.
Minnesota Power, Inc.
Minnkota Power Coop. Inc.
Terry Harbour
Randi K. Nyholm
Daniel L Inman
1
Muscatine Power & Water
Andrew J Kurriger
Negative
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
1
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
New York State Electric & Gas Corp.
North Carolina Electric Membership Corp.
Michael Jones
Cole C Brodine
Affirmative
Affirmative
1
1
1
1
Negative
Negative
Affirmative
Randy MacDonald
Bruce Metruck
Raymond P Kinney
Robert Thompson
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
1
1
1
1
1
1
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Terri Pyle
Jen Fiegel
Brad Chase
Daryl Hanson
John C. Collins
John T Walker
David Thorne
1
PPL Electric Utilities Corp.
Brenda L Truhe
1
Public Service Company of New Mexico
Laurie Williams
1
Public Service Electric and Gas Co.
Kenneth D. Brown
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Negative
SUPPORTS
THIRD PARTY
COMMENTS
1
1
1
1
1
1
1
1
1
1
1
1
1
1
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
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
1
1
1
1
1
1
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Michelle Clements
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
2
BC Hydro
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Dale Dunckel
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SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Negative
Affirmative
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
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
NERC Standards
2
2
2
2
2
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Barbara Constantinescu
Marie Knox
Alden Briggs
stephanie monzon
Charles H. Yeung
3
AEP
Michael E Deloach
Negative
3
3
3
3
Alabama Power Company
Alameda Municipal Power
Ameren Services
Arkansas Electric Cooperative Corporation
Robert S Moore
Douglas Draeger
Mark Peters
Philip Huff
Negative
3
Associated Electric Cooperative, Inc.
Chris W Bolick
3
3
3
3
3
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
3
Central Electric Power Cooperative
Adam M Weber
3
3
3
3
3
3
3
3
3
3
3
3
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Farmington
City of Palo Alto
City of Redding
City of Tallahassee
City of Ukiah
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Thomas C Duffy
Steve Alexanderson
Dennis M Schmidt
Andrew Gallo
Linda R Jacobson
Eric R Scott
Bill Hughes
Bill R Fowler
Colin Murphey
Charles Morgan
John Bee
Peter T Yost
Affirmative
Affirmative
Affirmative
3
Consumers Energy Company
Gerald G Farringer
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
East Kentucky Power Coop.
El Paso Electric Company
Entergy
Fayetteville Public Works Commission
FirstEnergy Corp.
Flathead Electric Cooperative
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
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Patrick Woods
Tracy Van Slyke
Joel T Plessinger
Allen R Wallace
Cindy E Stewart
John M Goroski
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
3
KAMO Electric Cooperative
Theodore J Hilmes
3
3
3
Kissimmee Utility Authority
Kootenai Electric Cooperative
Lakeland Electric
Gregory D Woessner
Dave Kahly
Mace D Hunter
3
Lincoln Electric System
Jason Fortik
Negative
3
Louisville Gas and Electric Co.
Charles A. Freibert
Negative
3
M & A Electric Power Cooperative
Stephen D Pogue
Negative
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Affirmative
Abstain
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
NERC Standards
COMMENTS
3
3
Manitoba Hydro
MEAG Power
Greg C. Parent
Roger Brand
Affirmative
Affirmative
3
MidAmerican Energy Co.
Thomas C. Mielnik
Negative
3
Mississippi Power
Jeff Franklin
Negative
3
Modesto Irrigation District
Jack W Savage
3
Muscatine Power & Water
John S Bos
3
3
3
3
Brian E Shanahan
Tony Eddleman
David R Rivera
Doug White
3
National Grid USA
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
Ramon J Barany
Negative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Donald Hargrove
David Burke
Ballard K Mutters
John H Hagen
Terry L Baker
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
3
3
3
3
3
Snohomish County PUD No. 1
Southern California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Mark Oens
David B Coher
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Westar Energy
Bo Jones
3
Wisconsin Electric Power Marketing
James R Keller
Negative
3
3
4
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Gregory J Le Grave
Michael Ibold
Raymond Phillips
Negative
Negative
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Negative
4
4
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
Ronnie Frizzell
Duane S Dahlquist
Affirmative
4
Buckeye Power, Inc.
Manmohan K Sachdeva
4
4
4
4
Central Lincoln PUD
City of Austin dba Austin Energy
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Shamus J Gamache
Reza Ebrahimian
Nicholas Zettel
John Allen
Affirmative
Affirmative
Affirmative
Affirmative
Margaret Powell
Affirmative
3
4
SUPPORTS
THIRD PARTY
COMMENTS Gary
Kruempel
MidAmerican
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Skyler Wiegmann
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
SUPPORTS
THIRD PARTY
COMMENTS
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
NERC Standards
4
Consumers Energy Company
Tracy Goble
Negative
4
4
4
4
4
4
4
Cowlitz County PUD
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Rick Syring
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Diana U Torres
Jack Alvey
4
Integrys Energy Group, Inc.
Christopher Plante
Negative
4
Madison Gas and Electric Co.
Joseph DePoorter
Negative
4
Modesto Irrigation District
Spencer Tacke
Negative
Barry R. Lawson
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
4
4
4
4
4
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
North Carolina Electric Membership Corp.
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Utility Services, Inc.
4
Wisconsin Energy Corp.
Anthony Jankowski
4
WPPI Energy
Todd Komplin
5
AEP Service Corp.
Brock Ondayko
5
Amerenue
Sam Dwyer
5
Arizona Public Service Co.
Scott Takinen
5
Arkansas Electric Cooperative Corporation
Brent R Carr
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
BC Hydro and Power Authority
Black Hills Corp
Bonneville Power Administration
BP Wind Energy North America Inc
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Buckeye Power, Inc.
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
Clement Ma
George Tatar
Francis J. Halpin
Carla Holly
Shari Heino
Chifong Thomas
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Michael Shultz
Wilket (Jack) Ng
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
5
Consumers Energy Company
David C Greyerbiehl
Negative
5
5
5
Cowlitz County PUD
CPS Energy
Dairyland Power Coop.
Bob Essex
Robert Stevens
Tommy Drea
4
4
4
4
4
4
4
4
SUPPORTS
THIRD PARTY
COMMENTS
Cecil Rhodes
Affirmative
John Lemire
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Affirmative
Affirmative
Negative
Abstain
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Negative
COMMENT
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
NERC Standards
5
Detroit Edison Company
Alexander Eizans
Negative
5
5
5
Marcus Ellis
Mike Garton
Dale Q Goodwine
Affirmative
Affirmative
Affirmative
5
5
5
5
5
5
5
5
5
5
5
5
5
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
E.ON Climate & Renewables North America,
LLC
El Paso Electric Company
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
5
Lincoln Electric System
Dennis Florom
5
5
5
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Karin Schweitzer
Rick Terrill
S N Fernando
Affirmative
Affirmative
Affirmative
David Gordon
Affirmative
Steven Grego
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
5
5
5
5
5
5
5
5
Dana Showalter
Gustavo Estrada
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
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
5
Northern Indiana Public Service Co.
William O. Thompson
Negative
5
5
5
5
5
5
Occidental Chemical
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Pacific Gas and Electric Company
Michelle R DAntuono
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
David Ramkalawan
Richard J. Padilla
Affirmative
Affirmative
5
PacifiCorp
Ryan Millard
Negative
5
5
Pattern Gulf Wind LLC
Portland General Electric Co.
Grit Schmieder-Copeland
Matt E. Jastram
Negative
5
PPL Generation LLC
Annette M Bannon
Negative
5
5
Tim Kucey
Steven Grega
5
5
5
5
5
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
5
5
5
5
5
5
5
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED see
NIPSCO Joe
O'Brien's
comments
Affirmative
Affirmative
Michiko Sell
Affirmative
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
Negative
Snohomish County PUD No. 1
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power
Sam Nietfeld
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
RECEIVED Kent Kujala of
Detroit Edison
Affirmative
Affirmative
Affirmative
Negative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
NERC Standards
5
Tennessee Valley Authority
David Thompson
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
5
5
U.S. Army Corps of Engineers
Utility System Effeciencies, Inc. (USE)
Westar Energy
Western Farmers Electric Coop.
Melissa Kurtz
Robert L Dintelman
Bryan Taggart
Clem Cassmeyer
5
Wisconsin Electric Power Co.
Linda Horn
Negative
5
6
6
6
Wisconsin Public Service Corp.
AEP Marketing
APS
Arkansas Electric Cooperative Corporation
Scott E Johnson
Edward P. Cox
Randy A. Young
Keith Sugg
Negative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
6
6
6
6
6
6
6
6
6
6
6
6
6
6
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
Florida Power & Light Co.
Great River Energy
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
Silvia P Mitchell
Donna Stephenson
6
Lincoln Electric System
Eric Ruskamp
6
6
6
6
6
6
6
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern California Power Agency
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Matthew Schull
Steve C Hill
6
Northern Indiana Public Service Co.
Joseph O'Brien
Negative
6
Oklahoma Gas & Electric Services
Jerry Nottnagel
Abstain
6
PacifiCorp
John Volz
Negative
6
6
6
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Carol Ballantine
Ty Bettis
Stephen C Knapp
6
PPL EnergyPlus LLC
Elizabeth Davis
Negative
6
PSEG Energy Resources & Trade LLC
Peter Dolan
Negative
6
6
6
6
6
6
6
6
6
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 California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina
Joseph T Marone
6
6
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED Ryan Millard
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
John J. Ciza
Negative
Michael C Hill
Abstain
https://standards.nerc.net/BallotResults.aspx?BallotGUID=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS Christina
Koncz PSEG
NERC Standards
6
6
6
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Affirmative
Peter H Kinney
Affirmative
6
Wisconsin Public Service Corp.
David Hathaway
Negative
6
Xcel Energy, Inc.
David F Lemmons
Negative
7
Alcoa, Inc.
Thomas Gianneschi
Negative
7
8
8
9
Thomas W Siegrist
Edward C Stein
Debra R Warner
Bruce Lovelin
Affirmative
Affirmative
Donald Nelson
Affirmative
9
10
EnerVision, Inc.
Central Lincoln PUD
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Florida Reliability Coordinating Council
10
Midwest Reliability Organization
Russel Mountjoy
10
10
10
10
10
10
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
6
9
9
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED
Diane J. Barney
Thomas G. Dvorsky
Linda Campbell
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=e76ffdb4-7f73-480a-a085-99607203b4b1[11/19/2013 11:18:25 AM]
Affirmative
COMMENT
RECEIVED
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Exhibit F
Standard Drafting Team Roster
Project 2010‐17 Definition of Bulk Electric System
Drafting Team Roster
Name and Title
Pete Heidrich
Mgr. of
Reliability
Standards and
SDT Chair
Company and
Address
Florida Reliability
Coordinating Council
1408 N. Westshore
Blvd.
Suite 1002
Tampa, FL 33607‐
4512
Contact Info
Barry Lawson
Associate
Director, Power
Delivery &
Reliability and
SDT Vice Chair
National Rural
Electric Cooperative
Association
4301 Wilson Blvd.
GR11‐253
Arlington, VA 22203
1.703.907.5781
[email protected]
oop
Jennifer Dering
Mgr. Operations
Planning –
Transmission
New York Power
Authority
123 Main St.
White Plains, NY
10601‐3170
1.914.287.3179
Jennifer.dering@nypa
.gov
1.813.207.7994
[email protected]
Bio
Peter Heidrich is Manager of Reliability Standards at the Florida Reliability
Coordinating Council (FRCC). Peter joined FRCC in August, 2008 after 16
years at DTE Energy (Detroit Edison) and 8½ years of military service in the
United States Navy Nuclear Power Program. Peter is responsible for the
development of the FRCC Regional Reliability Standards and associated
reliability related policies and procedures (i.e., Regional Criteria, Regional
Interpretations, & FAQs, Regional Definitions, etc.) and oversight of the
FRCC Reliability Standards Development Process. Additionally, Peter
actively participates as the FRCC representative in NERC Reliability
Standards development and on various committees, subcommittees, and
working groups (i.e., NERC Standards Committee (SC), SC Process
Subcommittee, ERO Regional Standards Group (Vice‐Chair), Functional
Model Working Group, and Results‐Based Standard Initiative).
Barry Lawson is the Associate Director, Power Delivery & Reliability at the
National Rural Electric Cooperative Association (NRECA). Barry joined
NRECA in April 2001, after 18 years in positions with Dominion Virginia
Power, Edison Electric Institute, Columbia Gas Transmission, and KEMA
Consulting. At NRECA, Barry’s current focus is on NERC reliability
policy/governance issues, standards development and compliance process
developments, and critical infrastructure protection policy issues. In
addition, Barry actively participates in BOT, MRC, and SC activities and he
is currently the Chair of NERC’s Critical Infrastructure Protection
Committee (CIPC).
Jennifer Dering is Manager of Operations Planning at the New York Power
Authority. Jennifer joined the New York Power Authority 18 years ago
after beginning her career at IBM. Jennifer is responsible for the short
term operational planning of NYPA’s transmission assets that range from
69 kV to 765 kV and span the entire state of New York. Jennifer has held a
variety of positions at NYPA prior to her current role in Transmission
including roles within Nuclear Licensing, Energy Efficiency, Project
Brian Evans‐
Mongeon
Pres. & CEO
Utility Services
25 Crossroad
Suite 201
Waterbury, VT 05676
1.802.552.4022
brian.evans‐
mongeon@utilitysvcs.
com
Phil Fedora
Asst. VP,
Reliability
Services
Northeast Power
Coordinating Council
1040 Avenue of the
Americas (6th Ave.)
10th Floor
New York, NY 10018‐
3703
1.212.840.4909
[email protected]
Management, and Engineering. Jennifer is also a licensed Professional
Engineer in the state of New York and a Certified Energy Manager.
Brian Evans‐Mongeon is the President and CEO of Utility Services, Inc., a
service firm formed in 2007, specializing in assisting registered entities in
the Electric Reliability Organization (ERO) program. As the
President and CEO of Utility Services, Brian is responsible for oversight of
ERO Compliance and Monitoring for client’s in regions across the U.S.; ISO
& NEPOOL markets; and Renewable Energy Trading and associated
activities. Utility Services is a member in five of the eight NERC regions
and its’ staff hold a number of committee positions within those regions.
Brian is a member of NPCC’s Compliance and Regional Standards
Committee, and is a participant in the NPCC task force for regional
standards on disturbance monitoring. At NERC, Brian is a participant in the
Standard Drafting Team for the Under Frequency Load Shedding program
(NERC Project 2007‐01), is currently a member of the Definition of Bulk
Electric System (BES) team (NERC Project 2010‐17), and is the current chair
of the Standard Drafting Team for Disturbance and Sabotage Reporting
(NERC Project 2009‐01). Previously, Brian has over twenty years of
experience in the electrical utility business working for both Green
Mountain Power Corporation as a Power Operations & Administration
Manager and Vermont Public Power Supply Authority as a Marketing
Services Manager.
Philip Fedora is the Assistant Vice President of Reliability Services,
Northeast Power Coordinating Council (NPCC) where he oversees a wide
range of power system reliability activities associated with the
coordination of system planning, system studies and protection, the
assessment of adequacy, and multi‐Area Regional planning. Phil is
responsible for NPCC’s Reliability Assessment and Performance Analysis
program area, including liaison with state, federal and provincial
governmental/regulatory officials. Phil joined NPCC in July, 1999 after 15
years at ISO‐New England/New England Power Planning (NEPOOL), where
he was responsible for the management of the ISO‐New England Power
Supply Reliability activities, and 8 years at Westinghouse Electric,
Advanced Systems Technology, providing consulting services for domestic
Ajay Garg
Mgr. Policy and
Approvals
Hydro One Networks 1.416.345.5420
483 Bay St., TCT St‐04 [email protected]
Toronto, Ontario,
om
Canada M5G 2P5
John P. Hughes
VP, Technical
Affairs
Electricity Consumers 1.202.682.1390
Research Council
[email protected]
1111 19th St. NW
Washington, DC
20036
and foreign utilities. Phil is NPCC’s representative on the NERC Planning
Committee, has authored several technical papers on power system
modeling and assessment, and is a member of the IEEE – Power
Engineering Society and
CIGRE. He is a licensed Professional Engineer in the Commonwealth of
Pennsylvania.
Ajay Garg is Manager, Policy & Approvals within Asset Management at
Hydro One Networks Inc (formerly Ontario Hydro). Ajay joined Hydro One
in 2000, after 15 years in positions with Nova Scotia Power and NPCC. At
Hydro One, Ajay’s current focus is on NERC reliability policy/governance
issues, standards development and compliance process, along with
addressing non‐jurisdictional regulatory issues. Ajay has been actively
involved with the development of NERC and NPCC Standards/Criteria for
many years along with his participation on the 2003 NERC blackout
investigation team. Ajay also represents Hydro One and/or Canada on
various other committees of IEC, IEEE, NERC, NPCC, CEA, and CSA. Ajay is a
Canadian representative on IEC TC8 and ACEC along with convener of TC8
HV Transmission Group, and member of NERC‐CCC and NPCC ‐CC. Ajay is a
licensed Professional Engineer in the Province of Ontario.
John Hughes is Vice President of Technical Affairs at the Electricity
Consumers Resource Council (ELCON), the national association of large
industrial consumers of electricity. John is responsible for managing
ELCON’s interventions before FERC, DOE, and related state regulatory
bodies. John is also author of ELCON policy papers and technical
documents on all facets of the electric industry. John joined ELCON in
1987 as technical director after serving as Director of Economic Research
at the Niagara Mohawk Power Corporation where he was previously
Associate Director of Corporate Planning. Prior to joining Niagara Mohawk
in 1982, John was Chief Economist at the Massachusetts Energy Facilities
Siting Council. John supervised the council’s technical staff regarding the
demand forecasts and supply plans of electric and natural gas utilities that
operated in the state. John was also directly involved with the council’s
adjudication of petitions to site transmission lines, natural gas pipelines
and gasification facilities, and nuclear power plants. John has been active
Jeffrey Mitchell
Director,
Engineering
Reliability First
320 Springside Dr.
Suite 300
Akron, OH 44333
Rich Salgo
Director,
Electric System
Operations
Sierra Pacific Power
PO Box 10100
Reno, NV 89520
with NERC since 1996, having been a member of the Commercial Practices
Working Group, the Market Interface Committee, and the Compliance and
Certification Committee (CCC).
1.330.247.3043
Jeff Mitchell is the Director of Engineering at ReliabilityFirst Corp. (RFC)
[email protected] where he oversees the reliability assessment and performance analysis
activities including resource and transmission assessment reports,
g
protection system mis‐operation review, event analysis, model
development, operations, and the regional standards process. Jeff joined
the East Central Area Reliability Coordination Agreement (ECAR) staff in
1997 after 17 years with Ohio Edison (now FirstEnergy) and subsequently
the ReliabilityFirst staff since its inception. Jeff facilitated the
development of the ReliabilityFirst BES definition in 2007 and now handles
the interpretation requests. Jeff is currently the chair of the NERC
Planning Committee and was the initial chair of the Eastern
Interconnection Reliability Assessment Group’s (ERAG) Management
Committee. He is also a licensed Professional Engineer in Ohio and
Pennsylvania.
1.775.834.5874
Rich Salgo is the Director of Electric System Control Operations at NV
[email protected] Energy, Inc., which includes the registered entities of Nevada Power
Company and Sierra Pacific Power Company. In this role, Rich is
responsible for the transmission, distribution, and balancing functions
conducted within the NV Energy control centers, including associated
operations engineering, training, and energy management system support
functions. Among the duties of his present position, Rich is responsible for
ensuring that policies, procedures, and processes are developed and
implemented pursuant to NERC and WECC Regional Standards, as well as
having responsibility for corporate initiatives in compliance with the CIP
Standards. Rich holds a Bachelor’s degree in Electrical Engineering, and he
joined the predecessor company, Sierra Pacific Resources, in 1984. In this
time, Rich has had experience in various facets of electric system design,
system protection, substation and line construction, and field operations.
Rich is a long‐standing member of the WECC Operating Committee,
participates on an advisory committee for the WECC Reliability
Coordinator, and is a member of the WECC Unscheduled Flow
Jason Snodgrass Georgia Transmission 1.770.270.7294
jason.snodgrass@gatr
Regulatory
Compliance
ans.com
Mgr.
Administrative Subcommittee. Rich is a licensed Professional Engineer in
the state of California, and also holds a NERC Operator Certification at the
RC level.
Jason Snodgrass is the Regulatory Compliance Manager at Georgia
Transmission Corporation. Jason has been employed in this role since
2008, after 7½ years of experience as a planning engineer. Jason is
primarily responsible for developing, maintaining, and training of GTC’s
compliance program. Additional responsibilities include
policy/governance, compliance process developments, performing self‐
audits of applicable mandatory standards, and performing self‐
assessments/consultation for new and revised NERC Standards prior to the
mandatory dates.
Jennifer Sterling
Director,
Transmission
Strategy and
Compliance
Exelon
2 Lincoln Center
Oakbrook Terrace, IL
60181
1.630.437.2764
jennifer.sterling@exel
oncorp.com
Jennifer Sterling is the Director, Transmission Strategy and Compliance for
Exelon Corporation. Jennifer has been employed by Exelon and its
subsidiary, Commonwealth Edison for 21 years. She has also held
positions in ComEd’s System Planning, Bulk Power Operations,
Transmission Policy, and Regulatory & Strategic Services Departments.
Jennifer is responsible for managing the Exelon NERC Reliability Standards
Compliance Program across the corporation and for providing leadership
for strategic and reliability initiatives for the ComEd and PECO transmission
facilities. Additionally, Jennifer was a member of the NERC Violations
Severity Levels Drafting Team and actively participates on Edison Electric
Institute and North American Transmission Forum Committees.
Jonathan Sykes
Mgr., System
Protection
Pacific Gas & Electric
1919 Webster St.
Room #409
Oakland, CA 94612
1.510.874.2691
[email protected]
Jonathan Sykes is Manager of System Protection at Pacific Gas and Electric
Company (PG&E) in California. Jonathan joined PG&E in June 2009 after 27
years at Salt River Project in Arizona where he worked as a principal
engineer in System Protection and Transmission Planning. Jonathan is
responsible for the oversight (application, design, and compliance) of the
40,000 protective relays at PG&E. Jonathan also serves as the Chairman
of the NERC System Protection and Control Subcommittee and has been
active in the committee for more than 5 years. Jonathan is also active on
the WECC Remedial Action Reliability Subcommittee and Relay Work
Group. He is also a Senior Member in IEEE and participates in the Power
System Relay Committee and chairs work groups. Jonathan has authored
and co‐authored papers concerning reliability and advanced application.
| File Type | application/pdf |
| File Title | Microsoft Word - Petition for Approval of Revised Definition of Bulk Electric System_12-12-13 |
| Author | tyrewalas |
| File Modified | 2013-12-13 |
| File Created | 2013-12-13 |