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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
BAL-005-1 AND FAC-001-3
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
Shamai Elstein
Senior Counsel
Candice Castaneda
Counsel
Andrew C. Wills
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
April 20, 2016
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II.
NOTICES AND COMMUNICATIONS ................................................................................ 6
III. BACKGROUND .................................................................................................................... 6
A.
Regulatory Framework ..................................................................................................... 6
B.
NERC Reliability Standards Development Procedure ..................................................... 7
C.
Procedural History............................................................................................................ 8
1.
BAL-005 ....................................................................................................................... 8
2.
FAC-001 ..................................................................................................................... 10
3.
BAL-006 ..................................................................................................................... 10
4.
Project 2010-14.2.1..................................................................................................... 11
IV. JUSTIFICATION FOR APPROVAL................................................................................... 12
A.
Proposed Reliability Standard BAL-005-1 .................................................................... 13
1.
Purpose and Overview of Proposed BAL-005-1 ........................................................ 13
2.
Applicability ............................................................................................................... 14
3.
Requirement-by-Requirement Justification................................................................ 15
B.
Proposed Reliability Standard FAC-001-3 .................................................................... 21
1.
Purpose and Overview of Proposed FAC-001-3 ........................................................ 21
2.
Applicability ............................................................................................................... 22
3.
Requirement-by-Requirement Justification................................................................ 23
C.
Enforceability of Proposed Reliability Standards BAL-005-1 and FAC-001-3 ............ 24
D.
Proposed Retirement of Reliability Standard BAL-006-2 ............................................. 25
1.
Overview .................................................................................................................... 25
2.
Requirement-by-Requirement Retirement Justification ............................................. 28
E.
Proposed NERC Glossary Definitions ........................................................................... 30
1.
Automatic Generation Control ................................................................................... 30
2.
Reporting ACE ........................................................................................................... 31
3.
Components of Reporting ACE .................................................................................. 32
4.
Pseudo-Tie .................................................................................................................. 34
5.
Balancing Authority ................................................................................................... 34
V.
EFFECTIVE DATE .............................................................................................................. 34
VI. CONCLUSION ..................................................................................................................... 36
Exhibit A
Proposed Reliability Standard BAL-005-1
Exhibit B
Proposed Reliability Standard FAC-001-3
Exhibit C
Redline of Reliability Standard BAL-006-2
Exhibit D
Implementation Plan for BAL-005-1
Exhibit E
Implementation Plan for FAC-001-3
Exhibit F
Implementation Plan for Retirement of BAL-006-2
Exhibit G
Analysis of Violation Risk Factors and Violation Severity Levels for BAL-005-1
Exhibit H
Analysis of Violation Risk Factors and Violation Severity Levels for FAC-001-3
Exhibit I
BAL-005-1 Mapping Document
Exhibit J
FAC-001-3 Mapping Document
Exhibit K
BAL-006-2 Mapping Document
Exhibit L
Calculating and Using Reporting ACE in a Tie Line Bias Control Program
Exhibit M
Order No. 672 Criteria
Exhibit N
Summary of Development History and Complete Record of Development
Exhibit O
Standard Drafting Team Roster
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
BAL-005-1 AND FAC-001-3
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby requests Commission
approval of:
•
proposed Reliability Standards BAL-005-1 (Balancing Authority Control) and FAC-0013 (Facility Interconnection Requirements) (Exhibits A and B),
•
proposed new or revised definitions to be incorporated into the Glossary of Terms Used
in NERC Reliability Standards (“NERC Glossary”) for the following terms: (1) Actual
Frequency, (2) Actual Net Interchange, (3) Scheduled Net Interchange, (4) Interchange
Meter Error, (5) Automatic Time Error Correction, (6) Reporting ACE, (7) Automatic
Generation Control (“AGC”), (8) Pseudo-Tie, and (9) Balancing Authority (“BA”)
(Exhibit D);
•
proposed retirement of currently effective Reliability Standards BAL-005-0.2b, FAC001-2, and BAL-006-2 (proposed retirement of BAL-006-2 is shown in Exhibit C);
•
associated Implementation Plans (Exhibits D, E, and F); and
•
associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”)
(Exhibits G and H) (collectively, “NERC’s Proposal”).
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2014).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the Federal Power Act on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary”), available at http://www.nerc.com/files/Glossary_of_
Terms.pdf.
2
1
NERC’s Proposal reflects revisions developed under Project 2010-14.2.1 Phase 2 of
Balancing Authority Reliability-based Controls (“Project”) to clarify, consolidate, streamline,
and enhance the Reliability Standards addressing frequency control. The NERC Board of
Trustees adopted proposed Reliability Standards BAL-005-1 and FAC-001-3 and related
retirement of BAL-006-2 on February 11, 2016.
NERC requests that the Commission approve NERC’s Proposal as just, reasonable, not
unduly discriminatory or preferential, and in the public interest. As required by Section 39.5(a)
of the Commission’s regulations, 4 this Petition presents the technical basis and purpose of
proposed Reliability Standards BAL-005-1 and FAC-001-3 and proposed retirement of BAL006-2, a summary of the development history and the complete record of development (Exhibit
N), and a demonstration that the proposed Reliability Standards meet the criteria identified by
the Commission in Order No. 672 (Exhibit M). 5
I.
EXECUTIVE SUMMARY
Reliable Operation of the Bulk Power System (“BPS”) depends on maintaining frequency
within predefined boundaries approximating 60 Hertz (“Hz”). Frequency is the speed of rotation
of an Interconnection, measured in cycles per second (or Hz). As a result, multiple NERC
Reliability Standards, such as currently effective Reliability Standard BAL-005-0.2b, operate
together to maintain reliable frequency control. The Project standard drafting team (“SDT”)
proposed revisions to currently effective Reliability Standards BAL-005-0.2b and FAC-001-2,
modifications to several NERC definitions, and the retirement of Reliability Standard BAL-006-
4
18 C.F.R. § 39.5(a) (2014).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at PP 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
5
2
2, to clarify, consolidate, streamline, and enhance the manner in which NERC Reliability
Standards address certain issues related to frequency control. The SDT developed the proposed
modifications after review of Commission directives, Paragraph 81 Criteria, 6 and
recommendations by the periodic review team that examined Reliability Standards BAL-0050.2b and BAL-006-2 in 2013 (“PRT”).
Currently effective Reliability Standard BAL-005-0.2b facilitates efforts to maintain
frequency at 60 Hz by supporting the accurate and consistent calculation of a key frequency
control and reliability indicator – Reporting Area Control Error (“Reporting ACE”). Reporting
ACE represents a Balancing Authority Area’s (“BAA”) Area Control Error (“ACE”) measured
in megawatts (“MW”) as the difference between the BAAs Actual and Scheduled Net
Interchange, plus its Frequency Bias Setting obligation and meter error corrections. 7 Reporting
ACE helps Responsible Entities provide reliable frequency control by indicating the current state
of the entity’s contribution to Reliability. As such, Reporting ACE is a key input to other
frequency related Reliability Standards, such as BAL-001 and BAL-002.
Because Reporting ACE is key measure to maintaining frequency at 60 Hz, Responsible
Entities must accurately calculate Reporting ACE using complete and correct data. NERC’s
Proposal clarifies and refines Requirements for accurate, consistent, and complete Reporting
ACE calculations. The proposed revisions include relocating Requirements to confirm that
interconnecting Facilities are within a BAA’s metered boundary, and thereby captured in the
6
N. Am. Elec. Reliability Corp., 138 FERC ¶ 61,193, at P 81 (“March 2012 Order”), order on reh’g and
clarification, 139 FERC ¶ 61,168 (2012); Petition of the North American Electric Reliability Corporation for
Approval of Retirement of Requirements in Reliability Standards, Docket No. RM13-8-000, at Exhibit A
(“Paragraph 81 Criteria”) (filed Feb. 28, 2013); N. Am. Elec. Reliability Corp., Order No. 788, 145 FERC ¶ 61,147
(2013).
7
As explained in this Petition, NERC’s Proposal includes revising the definition of Reporting ACE to
include Automatic Time Error Correction (“ATEC”) when calculating Reporting ACE in the Western
Interconnection.
3
Reporting ACE calculation, into Reliability Standard FAC-001-3. Similarly, NERC’s Proposal
includes moving Requirement R3 of currently effective Reliability Standard BAL-006-2 into
proposed Reliability Standard BAL-005-1, as this Requirement helps ensure that BAs will use
consistent data sources to calculate Reporting ACE. To support these improvements to
Reporting ACE calculations, NERC’s Proposal would also revise the following definitions:
Actual Frequency, Actual Net Interchange, Scheduled Net Interchange, Interchange Meter Error,
Automatic Time Error Correction, Reporting ACE, Automatic Generation Control (“AGC”),
Pseudo-Tie, and Balancing Authority.
NERC’s Proposal would also retire ineffective or duplicative Requirements that do not
affect reliability (such as commercial calculations). For example, NERC proposes retiring the
remaining Requirements in Reliability Standard BAL-006-2, as they pertain to administrative or
commercial obligations such as the calculation of Inadvertent Interchange. The SDT prepared a
White Paper regarding Inadvertent Interchange accumulations and their associated paybacks to
explain inadvertent interchange calculations. Based on this White Paper, the SDT developed an
Inadvertent Interchange Guideline to help ensure a seamless transition to the proposed integrated
Reliability Standards. The Operating Committee (“OC”) is currently reviewing the draft
Inadvertent Interchange Guideline.
Together, these revisions and enhancements will improve reliability by supporting efforts
to maintain Interconnection frequency at 60 Hz in a manner consistent with Commission
directives, technological developments, and NERC’s current framework of integrated Reliability
Standards. NERC requests that the Commission approve proposed Reliability Standards BAL005-1 and FAC-001-3 effective on the first day of the first calendar quarter that is twelve months
after the effective date of the applicable governmental authority’s order approving the standard,
4
pursuant to the Implementation Plans attached at Exhibit D and E. In addition, NERC requests
that the Commission approve retirement of Reliability Standard BAL-006-2 upon the effective
date of Reliability Standard BAL-005-1 and the OC’s approval of an Inadvertent Interchange
Guideline, per the Implementation Plan attached at Exhibit F. 8 Finally, NERC also requests that
the proposed definitions for Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Metter Error, and ATEC become effective immediately
after the July 1, 2016 effective date of Reliability Standard BAL-001-2. 9 Finally, NERC
requests that the proposed definitions for AGC, Pseudo-Tie, and Balancing Authority become
effective upon the effective date of Reliability Standard BAL-005-1. The effective dates
associated with NERC’s Proposal will ensure seamless transition to the improved, integrated
Reliability Standards proposed in this Petition.
8
Reliability guidelines are not binding norms or mandatory requirements.
See, BAL-005-1 Implementation Plan, attached hereto as Exhibit D. The SDT intended that the definition
of “Reporting ACE” approved in Real Power Balancing Control Performance Reliability Standard, Order No. 810,
151 FERC ¶ 61,048 at P 43 (2015) never take effect; however, NERC understands that there may be a period that
the definition of “Reporting ACE” approved in Order No. 810 is in effect while the Commission reviews this
Petition.
9
5
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to: 10
Shamai Elstein*
Senior Counsel
Candice Castaneda
Counsel
Andrew C. Wills*
Associate Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
III.
Howard Gugel*
Director of Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
[email protected]
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 11 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 Electric Reliability Organization (“ERO”) that
would be charged with developing and enforcing mandatory Reliability Standards, subject to
Commission approval. Section 215(b)(1) of the FPA states that all users, owners, and operators
of the Bulk-Power System in the United States will be subject to Commission-approved
Reliability Standards. 12 Section 215(d)(5) of the FPA authorizes the Commission to order the
ERO to submit a new or modified Reliability Standard. 13 Section 39.5(a) of the Commission’s
10
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 (2014), to allow the inclusion
of more than two persons on the service list in this proceeding.
11
16 U.S.C. § 824o (2012).
12
Id. § 824o(b)(1).
13
Id. § 824o(d)(5).
6
regulations requires the ERO to file with the Commission for its approval each Reliability
Standard that the ERO proposes to become mandatory and enforceable in the United States, and
each modification to a Reliability Standard that the ERO proposes to be made effective. 14
The Commission is vested with 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. The Commission also exercises oversight regarding proposals to retire Reliability
Standards. 15 Pursuant to Section 215(d)(2) of the FPA 16 and Section 39.5(c) of the
Commission’s regulations, “the Commission will give due weight to the technical expertise of
the Electric Reliability Organization” with respect to the content of a Reliability Standard. 17
B.
NERC Reliability Standards Development Procedure
NERC’s Proposal was developed in an open and fair manner and in accordance with the
Commission-approved Reliability Standard development process. 18 NERC develops Reliability
Standards in accordance with Section 300 (Reliability Standards Development) and Appendix
14
18 C.F.R. § 39.5(a).
See e.g., NERC Standards Processes Manual, at Section 4.19 of the NERC Rules of Procedure, infra n. 19.
16
16 U.S.C. § 824o(d)(2).
17
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.”).
15
7
3D (NERC Standard Processes Manual) of the Commission approved NERC Rules of
Procedure. 19
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s proposed rules provide for reasonable notice and opportunity for public comment, due
process, openness, and a balance of interests in developing Reliability Standards, 20 and thus
satisfy certain of the criteria for approving Reliability Standards. 21 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 stakeholders must approve, and
the NERC Board of Trustees must adopt a Reliability Standard before the Reliability Standard is
submitted to the Commission for approval.
C.
Procedural History
1.
BAL-005
In Order No. 693, the Commission evaluated 107 Reliability Standards, including
Reliability Standard BAL-005-0 (Automatic Generation Control). 22 In approving BAL-005-0,
the Commission directed NERC to develop modifications to: (i) create a process to calculate the
minimum regulating reserve for a BA with respect to expected load and generation variation and
transactions being ramped into or out of the BA, (ii) revise the title of the Reliability Standard to
be neutral as to the source of regulating reserves and to include technically qualified demandside management (“DSM”) and direct control load management as regulating reserves, (iii)
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.
21
Order No. 672, supra n. 18, at PP 268, 270.
22
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).
8
clarify the required type of transmission or backup plans when receiving regulation from outside
the BA when using non-firm service, (iv) include levels of Non-Compliance and a Measure that
provides for a verification process over the minimum required automatic generation control or
regulating reserves that a BA must maintain, and (v) “consider those [Xcel and FirstEnergy]
suggestions in its Reliability Standards development process.” 23
On December 19, 2007, NERC submitted a formal interpretation request and proposed
that the Commission approve the interpretation as Reliability Standard BAL-005-0a. 24 While
that interpretation was pending with the Commission, NERC withdrew the request and submitted
its second interpretation, titled BAL-005-0b, to amend the proposed interpretation. 25 The
Commission approved the second interpretation on July 21, 2008, in Docket No. RM08-7-000. 26
In 2009 and 2012, NERC filed errata to Reliability Standard BAL-005-0b, thus resulting in
BAL-005-0.1b in 2009 and BAL-005-0.2b in 2012. 27 The Commission approved BAL-005-0.1b
and BAL-005-0.2b on May 13, 2009 and September 13, 2012, respectively. 28 The current
Project addresses remaining Commission’s directives related to BAL-005. See infra, Section
IV.A.
23
Order No. 693, supra n. 22, at PP 397, 418-420.
Petition of the North American Electric Reliability Corporation for Approval of Formal Interpretations to
Reliability Standards, Docket No. RM06-16-000 (filed Dec. 19, 2007) (requesting clarification of Requirement R17
of BAL-005-0).
25
Petition of the North American Electric Reliability Corporation for Approval of Formal Interpretation to
Reliability Standards and Withdrawal of Prior Formal Interpretation (“Interpretation Petition”), Docket No. RM087-000 (filed Apr. 15, 2008) (requesting withdrawal of first interpretation request and approval of a revised
interpretation to clarify Requirement R17 of BAL-005-0).
26
Modification of Interchange and Transmission Loading Relief Reliability Standards; and Electric
Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards, Order No. 713, 124
FERC ¶ 61,071 (2008).
27
See, e.g., North American Electric Reliability Corporation Petition for Approval of Errata Changes to
Seven Reliability Standards, Docket No. RD12-4-000 (filed June 5, 2012).
28
See, e.g., N. Am. Elec. Reliability Corp., Docket No. RD09-2-000 (May 13, 2009) (unpublished letter
order); N. Am. Elec. Reliability Corp., Docket No. RD12-4-000 (Sept. 13, 2012) (unpublished letter order).
24
9
2.
FAC-001
In Order No. 693, the Commission approved Reliability Standard FAC-001-0 with no
directives. 29 On July 30, 2012, NERC submitted Reliability Standard FAC-001-1, along with
several other proposed standards, to revise the applicability of those Reliability Standards to
include generator interconnection Facilities. The Commission approved these standards in Order
No. 785 on September 19, 2013. 30 Finally, on August 22, 2014, NERC submitted a petition for
approval of Reliability Standard FAC-001-2 to “ensure appropriate coordination and
communication regarding the interconnection of Facilities.” 31 The Commission approved FAC001-2 by letter order on November 6, 2014. 32
3.
BAL-006
In Order No. 693, the Commission approved Reliability Standard BAL-006-1
(Inadvertent Interchange). 33 In doing so, the Commission directed NERC to develop
modifications to BAL-006-1 to (i) include Measures concerning the accumulation of large
inadvertent imbalances and additional Levels of Non-Compliance, and (ii) modify the regional
differences to reference only current Reliability Standards. On November 20, 2009, NERC
submitted BAL-006-2, which removed the “RTO Inadvertent Interchange Accounting Waiver”
from BAL-006-1 that was implemented to accommodate Midwest ISO as a multi-BA market. 34
29
Order No. 693, supra n. 22, at P 680.
Generator Requirements at the Transmission Interface, Order No. 785, 144 FERC ¶ 61,221 (2013).
31
Petition of the North American Electric Reliability Corporation for Approval Of Proposed Reliability
Standards for Facility Connection Requirements FAC-001-2 and FAC-002-2, Docket No. RD14-12-000 (filed Aug.
22, 2014).
32
N. Am. Elec. Reliability Corp., Docket No. RD14-12-000 (Nov. 6, 2014) (unpublished letter order).
33
Order No. 693, supra n. 22, at PP 439, 444.
34
Petition of the North American Electric Reliability Corporation for Approval Of Two Reliability Standards
Revisions to Withdraw MISO Waivers, Docket No. RM06-16-000 (filed Nov. 20, 2009).
30
10
Midwest ISO’s eventual transition to a single BA mooted the need for any regional waivers, and
the Commission approved BAL-006-2 on January 6, 2011. 35
4.
Project 2010-14.2.1
The Project resulted from NERC’s efforts over the past several years to address the
directive in Order No. 693 to create a continent-wide Contingency Reserve standard. Over time,
this initiative was separated into two phases. Phase 2 ultimately led to the proposed
modifications described in this Petition. At its genesis, Phase 2 was labeled Project 2010-14.2
and involved BAL-004, 36 BAL-005, and BAL-006. Before work in Phase 2 began, NERC
implemented a number of initiatives to improve Reliability Standards, including retirement of
unnecessary or redundant requirements under Paragraph 81 Criteria, 37 consideration of
Independent Expert Review Panel recommendations, and implementation of results-based
concepts. As such, Project 2010-14.2 evolved into a periodic review, and on September 19,
2013, the Standards Committee (“SC”) appointed the PRT. The PRT presented recommended
revisions to BAL-005-0.2b and BAL-006-2 based on its review of the standards and submitted a
Standard Authorization Request (“SAR”) to the SC for the development of these revisions.
The SDT posted the first draft of proposed Reliability Standards BAL-005-1, BAL-0063, and FAC-001-3 on July 30, 2015. Based on industry feedback, the SDT eventually ceased
development on BAL-006-3, consolidated certain aspects of BAL-006-2 in BAL-005-1, and
proposed retirement of BAL-006-2. The final posting in the Project included proposed
35
Order Approving Revisions to Two Reliability Standards and Directing a Compliance Filing, 134 FERC ¶
61,007 (2011) (directing NERC to submit a compliance filing identifying the entity or entities that are responsible
under Reliability Standard BAL-006-2 for calculating Inadvertent Interchange among the Local Balancing Authority
Areas within the Midwest ISO BAA); N. Am. Elec. Reliability Corp., Docket No. RD10-4-000 (May 16, 2011)
(unpublished letter order) (approving NERC’s February 22, 2011 Compliance Filing explaining that there is only
one Midwest ISO BAA).
36
NERC later separated Reliability Standard BAL-004-0 into an independent project, Project 2010-14.2.2.
37
Paragraph 81 Criteria, supra n. 7.
11
Reliability Standards BAL-005-1 and FAC-001-3, several revised NERC Glossary definitions,
and retirement of Reliability Standard BAL-006-2. Industry approved NERC’s Proposal through
the Commission approved NERC Reliability Standard Development Process set forth in
Appendix 3D of the NERC Rules of Procedure. 38 The development history of Reliability
Standard BAL-005-1, BAL-006-2, and FAC-001-3 is attached as Exhibit N.
IV.
JUSTIFICATION FOR APPROVAL
As described above, NERC’s Proposal represents the technical findings of the SDT based
on its review of the PRT recommendations, as well as stakeholder comments throughout the
Project. NERC’s Proposal is intended to replace and retire currently effective Reliability
Standards BAL-005-0.2b, BAL-006-2, and FAC-001-2. NERC’s Proposal represents substantial
improvements over existing Reliability Standards by helping to support more accurate and
comprehensive calculation of Reporting ACE and satisfying all remaining Commission
directives for Reliability Standards BAL-005 and BAL-006. As discussed below and in Exhibit
M, NERC’s Proposal satisfies the Commission’s criteria in Order No. 672 and is just,
reasonable, not unduly discriminatory or preferential, and in the public interest.
The following subsections provide (i) a description of each proposed Reliability
Standard, its reliability purpose, the applicable entities, and a requirement-by-requirement
justification for each proposed Reliability Standard, (ii) a description of enforceability, (iii)
justification for retirement of Reliability Standard BAL-006-2, and (iv) justification for NERC’s
proposed revised definitions.
38
See infra n. 19.
12
A.
Proposed Reliability Standard BAL-005-1
1.
Purpose and Overview of Proposed BAL-005-1
The purpose of proposed Reliability Standard BAL-005-1 is to establish “requirements
for acquiring data necessary to calculate Reporting Area Control Error (Reporting ACE).” As
further explained in the purpose statement for BAL-005-1, the standard “specifies minimum
periodicity, accuracy, and availability requirement for acquisition of the data and for providing
the information to the System Operator.” Proposed BAL-005-1 is designed to ensure that BAs
properly calculate and communicate Reporting ACE. As explained below, proposed Reliability
Standard BAL-005-1 is an improvement to BAL-005-0.2b, as it consolidates unnecessary or
repetitive Requirements and moves certain metrics for calculating Reporting ACE to the revised,
proposed definition of Reporting ACE. Further, pursuant to a Commission directive in Order
No. 693, the title of the Reliability Standard has been modified to “Balancing Authority Control”
to reflect the connection to Reporting ACE and resource-neutral requirements. 39
As stated above, Reporting ACE is an indicator of operational frequency and helps
Responsible Entities provide reliable frequency control by indicating the current state of the
entity’s contribution to Reliability. Proposed Reliability Standard BAL-005-1 supports system
frequency by requiring entities to properly calculate and communicate Reporting ACE or notify
the Reliability Coordinator (“RC”) when it is not possible to calculate Reporting ACE.
Specifically, the proposed standard requires entities to take measures to obtain requisite data
necessary to calculate Reporting ACE to enable Responsible Entities to balance resources and
39
Order No. 693, supra n. 22, at P 404. In the same paragraph, the Commission directed NERC to “allow the
inclusion of technically qualified DSM and direct control load management as regulating reserves…” NERC notes
that Requirement R2 of BAL-005-0.2b, which required entities to maintain regulating reserves, was retired on
January 21, 2014 (see supra n. 7). Reliability Standard BAL-001-2 and proposed Reliability Standard BAL-002-2
(submitted to the Commission on January 29, 2016 in Docket No. RM16-7-000) allows for the inclusion of DSM.
Finally, the revised definition of Automatic Generation Control, described in this Petition, assures a resource neutral
process for controlling demand and resources. Accordingly, this directive has been addressed.
13
demand under Tie-Line Bias Control. The proposed Requirements of BAL-005-1 will improve
reliability by ensuring that BAs have situational awareness capabilities that support BA decisionmaking responsibilities. These revisions also address all remaining Commission directives, as
discussed below in Section IV.A.3.
2.
Applicability
The Requirements in proposed Reliability Standard BAL-005-1 apply to BAs. NERC’s
Proposal would move Requirements suitable for other Registered Entities to Reliability Standard
FAC-001-3 and retire Requirements that are redundant or ineffective.
As explained in the BAL-005-1 Mapping Document (Exhibit I), the requirements in
Reliability Standard BAL-005-0.2b that apply to Generator Operators (“GOP”) and
Transmission Operators (“TOPs”) have been moved to Requirements R3 and R4 in proposed
Reliability Standard FAC-001-3. NERC proposes to move these requirements to FAC-001-3
because the Facilities Design, Connections, and Maintenance (FAC) Reliability Standard suite is
the appropriate location for a requirement for Transmission Owners (“TOs”) and Generator
Owners (“GO”) to define a process for confirming that interconnecting Facilities are within a
BAA’s metered boundaries. As described in Section IV.B below, Reliability Standard FAC-0013 sets out Interconnection-related requirements. Further, NERC proposes to retire Requirement
R1.3 in existing Reliability Standard BAL-005-0.2b as redundant and unnecessary, consistent
with the Commission’s approval of removal of the Load Serving Entity (“LSE”) functional
registration category from the NERC Compliance Registry and the limited utility of requiring the
LSE to ensure that its loads are included within the metered boundaries of a BAA. 40
40
See, e.g., Petition of the North American Electric Reliability Corporation for Approval of Risk-Based
Registration Initiative Rules of Procedure Revisions, Docket No. RR15-4-000 (filed Dec. 11, 2014); Order on
Electric Reliability Organization Risk Based Registration Initiative and Requiring Compliance Filing, 150 FERC ¶
14
3.
Requirement-by-Requirement Justification
Currently effective Reliability Standard BAL-005-0.2b consists of seventeen
requirements. The SDT determined that Requirements R2, R7, and R15 of currently effective
BAL-005-0.2b are redundant, ineffective, and should be retired based on Commission-approved
Paragraph 81 Criteria. Further, the SDT proposes to incorporate Requirements R9, R10, and
R11 into the proposed definitions used in the calculation of Reporting ACE. NERC proposes to
consolidate the remaining Requirements and related NERC Glossary definitions to improve
clarity and efficiency. As a result, proposed Reliability Standard BAL-005-1 consists of seven
Requirements that address the Commission’s outstanding directives in Order No. 693 41 and
comply with the criteria for standard development in Order No. 672, as further supported in
Exhibit M.
a)
Requirement R1
R1. The Balancing Authority shall use a design scan rate of no more than six seconds in
acquiring data necessary to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
A critical component of the accuracy of Reporting ACE is the timeliness of collection of
sample data used to calculate the Reporting ACE. Proposed Requirement R1 requires BAs to
acquire real-time operation information as it relates to the calculation of Reporting ACE using a
design scan rate of no more than six seconds. By mandating that BAs use a constant design scan
rate for data samples used to calculate Reporting ACE, Requirement R1 will ensure that
information provided to Operators regarding calculation of Reporting ACE exposes real-time
61,213 (2015); Compliance Filing of the North American Electric Reliability Corporation and Petition for Approval
of Rules of Procedure Revisions Compliance Filing, Docket No. RR15-4-001 (filed July 17, 2015); Order on
Compliance Filing, 153 FERC ¶ 61,024 (2015).
41
Order No. 693, supra n. 22, at P 356.
15
conditions and not historical data. A required design scan rate of less than or equal to six
seconds ensures that this information is real-time information, and it limits the latency associated
with data collection. 42 Given the inherent connection between Reporting ACE and frequency,
Requirement R1 will allow operators to maintain reliability using accurate, timely information
about Reporting ACE.
b)
Requirement R2
R2. A Balancing Authority that is unable to calculate Reporting ACE for more than 30consecutive minutes shall notify its Reliability Coordinator within 45 minutes of the
beginning of the inability to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
As the entity responsible for coordinating reliability across a wide area system, the RC
must be aware of instant system conditions in order to assess unintended reliability scenarios.
Proposed Requirement R2 mandates information sharing by requiring BAs to provide RCs with
real-time information regarding the BA’s inability to calculate Reporting ACE. Proposed
Requirement R2 improves upon currently effective Requirement R6 of Reliability Standard
BAL-005-0.2b because it maintains the currently effective 30-minute threshold in between
calculations of Reporting ACE and clarifies the performance expectations for notification from
the BA to the RC of an exceedance of this 30-minute threshold. By requiring BAs to notify the
RC within 15 minutes of the end of the 30-minute period (or 45 minutes of the beginning of an
inability to determine Reporting ACE), proposed Reliability Standard BAL-005-1 ensures that
RCs are constantly apprised of disturbances in Reporting ACE calculations. This assurance
enables the RC to coordinate with member BAs and take action as necessary.
42
See Exhibit L, Calculating and Using Reporting ACE in a Tie Line Bias Control Program at n. 18.
16
c)
Requirement R3
R3. Each Balancing Authority shall use frequency metering equipment for the calculation
of Reporting ACE: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
3.1. that is available a minimum of 99.95% for each calendar year; and,
3.2. with a minimum accuracy of 0.001 Hz.
Proposed Requirement R3 combines aspects of Requirements R8 and R17 of currently
effective BAL-005-0.2b and sets a standard for frequency metering equipment that ensures that
BAs consistently gather accurate frequency data to support Reporting ACE calculations.
Proposed Requirement R3 also addresses two Commission directives in Order No. 693. In Order
No. 693, the Commission directed NERC “to revise the Violation Risk Factor for BAL-005-0,
Requirement R17 to medium.” 43 The Commission also stated that, “the comments of Xcel and
FirstEnergy should be addressed by the ERO when this Reliability Standard [BAL-005-0] is
revisited as part of the ERO’s Work Plan.” 44 Xcel and FirstEnergy questioned the application of
Requirement R17 to equipment that would require unnecessary costs of compliance for little
reliability benefit. 45
In its Interpretation Petition filed with the Commission on April 15, 2008, NERC
addressed part of FirstEnergy’s concern by clarifying that Requirement R17 of BAL-005-0
applies to devices within operations control rooms and external devices that “transmit said time
error and frequency information from a source remote to the control centers.” 46 As NERC
43
Order No. 693, supra n. 22, at P 58.
Id. at P 415 (directing NERC to consider comments by Xcel and FirstEnergy regarding the applicability of
Requirement R17 of Reliability Standard BAL-005-0).
45
Id. at PP 410-411 (noting Xcel’s comment suggesting that Requirement R17 should be limited only to
equipment necessary for interchange metering in balancing areas where errors in generating metering are critical for
imbalance calculations; also noting FirstEnergy’s comment requesting that the Commission limit the devices
applicable under Requirement R17 to “control center devices” and noted that the term “check” in Requirement R17
should be clarified).
46
Interpretation Petition at p. 8, supra n. 26.
44
17
explained, “time error and frequency devices that serve as input into the reporting or compliance
of the ACE equation…must be annually checked and calibrated.” 47
Proposed Requirement R3 addresses the remainder of the comments of Xcel and
FirstEnergy not addressed in the Interpretation Petition, as NERC proposes to retire part of
currently effective Requirement R17 of BAL-005-0.2b as moot and move part of the existing
Requirement to proposed Requirement R3. Proposed Requirement R3 includes streamlined
obligations to use specific frequency metering equipment that is necessary for operation of AGC
and accurate calculation of Reporting ACE, as this ensures that costs associated with
implementation are commensurate with reliability benefit. Finally, as described below in Section
IV.C, NERC has assigned Requirement R3 a VRF of “Medium” with a Time Horizon of “Realtime Operations” based on Commission-approved guidelines, thus addressing the remaining
Commission directive in Order No. 693. 48
d)
Requirement R4
R4. The Balancing Authority shall make available to the operator information associated
with Reporting ACE including, but not limited to, quality flags indicating missing or
invalid data. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
System Operators use Reporting ACE as a critical input to assess whether and to what
extent actions or operating instructions are necessary to maintain system stability. Proposed
Requirement R4 links Reporting ACE to an entity’s operations by requiring BAs to share
Reporting ACE with System Operators. Thus, proposed Requirement R4 combines elements of
currently effective Requirements R14 and R16 of Reliability Standard BAL-005-0.2b that
require BAs to provide real-time values and Reporting ACE data status to operators. This
47
48
Id.
Order No. 693, supra n. 22, at P 58.
18
consolidation ensures that BAs provide all Reporting ACE data to operators, thereby reducing
the possibility of that undue delay or incorrect data might cause adverse events.
e)
Requirement R5
R5. Each Balancing Authority’s system used to calculate Reporting ACE shall be available a
minimum of 99.5% of each calendar year. [Violation Risk Factor: Medium] [Time Horizon:
Operations Assessment]
Proposed Requirement R5 introduces a new obligation into Reliability Standard BAL005 to assure the availability of a BA’s system used to calculate Reporting ACE. This
Requirement will help ensure that entities can rely on Reporting ACE calculations provided by a
BA. Requirement R5 differs from Requirement R4 because proposed Requirement R4 obligates
entities to provide all data associated with Reporting ACE at a given time, whereas proposed
Requirement R5 establishes constant availability of the system used to calculate Reporting ACE.
f)
Requirement R6
R6. Each Balancing Authority that is within a multiple Balancing Authority Interconnection
shall implement an Operating Process to identify and mitigate errors affecting the accuracy of
scan rate data used in the calculation of Reporting ACE for each Balancing Authority Area.
[Violation Risk Factor: Medium] [Time Horizon: Same-day Operations]
Scan rate data is a critical input in the calculation of Reporting ACE, and inaccurate
Reporting ACE can lead to inappropriate operating decisions. Persistent errors in calculation of
Reporting ACE may cause operators to question Reporting ACE, thus delaying decisions and
causing adverse consequences. To mitigate instances of inaccurate Reporting ACE calculations,
Requirement R6 supports the accurate collection of scan rate data used in calculating the
Reporting ACE by requiring entities to design procedures in an Operating Process to identify and
mitigate errors.
A successful Operating Process should include certain steps to support accurate
Reporting ACE. First, the Operating Process must allow BAAs to agree upon hourly
19
accumulated Tie Line megawatt hours (“MWh”) values to mitigate or avoid errors in calculating
Reporting ACE. Second, the Operating Plan should include the ability to compare the
integration of instantaneous metered values with accumulated MWh values for each BA. Third,
to establish that accumulated MWh metering for one BA is equivalent to accumulated MWh on
Adjacent Balancing Authorities (“ABA”) on the same tie line, the Operating Plan should include
a comparison of a BA’s accumulated MWh value with the accumulated MWh value for its ABA.
If there is a difference between these values, the Operating Process should instruct the BAs to
agree on a common value for the tie lines to accommodate the difference between the
accumulated values or some other method to address the inconsistency. 49
g)
Requirement R7
R7. Each Balancing Authority shall ensure that each Tie Line, Pseudo-Tie, and Dynamic
Schedule with an Adjacent Balancing Authority is equipped with: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
7.1. a common source to provide information to both Balancing Authorities for the scan
rate values used in the calculation of Reporting ACE; and,
7.2. a time synchronized common source to determine hourly megawatt-hour values
agreed-upon to aid in the identification and mitigation of errors under the Operating
Process as developed in Requirement R6.
Because Reporting ACE is an essential measurement of a BA’s contribution to the
reliability of an Interconnection, consistency in the calculation of Reporting ACE across BAs is
important to avoid confusion and delayed or incorrect operator action. The use of common
source data among BAs ensures consistency in the calculation of Reporting ACE. Proposed
49
The SDT developed provisions in the Whitepaper (attached herein as Exhibit L) to cover the practice of
comparing the hourly megawatt-hour values gathered at the end of the hour against the hourly integrated values of
the scan-rate data operated to, in order to determine if significant error exists. See, Periodic Review of BAL-0050.2b – Automatic Generation Control and BAL-006-2 – Inadvertent Interchange (Recommendation to Revise both
Standards), pg. 21 (May 22, 2014), accessible online at http://www.nerc.com/pa/Stand/Project
%20201014%202%20Phase%202%20of%20Balancing%20Authority%20Re/Recommendation_to_Revise_BAL005_and_BAL-006_Clean_BAL_PRT_FINAL_07162014.pdf.
20
Requirement R7 is designed based on Requirement R12, R13, and R14 of currently effective
Reliability Standard BAL-005-0.2b and Requirement R3 of Reliability Standard BAL-006-2 to
address common source data issues for Tie Lines, Pseudo-Ties, and Dynamic Schedules.
Proposed Requirement R7 accomplishes these issues by obligating ABAs to utilize common
source data with respect to scan rate values used when calculating Reporting ACE and a time
synchronized common source when identifying and mitigating errors per the Operating Process
developed under proposed Requirement R6. 50 This will help avoid confusion and inaccuracies
that may arise if ABAs use inconsistent data sources. As recommended by the PRT, proposed
Requirement R7 now includes a requirement for BAs to agree on common values to be used in
real-time.
B.
Proposed Reliability Standard FAC-001-3
Proposed Reliability Standard FAC-001-3 consists of the same four Requirements that
are in currently effective Reliability Standard FAC-001-2, with new Requirement subparts added
to Requirement R3 and Requirement R4 to extend certain obligations to TOs and GOs. As these
new sub-requirements are the only proposed revisions, the justification provided below is limited
to these sub-requirements. As further supported in Exhibit M, the proposed Requirements
outlined below comply with the Commission’s criteria for Reliability Standards set forth in
Order No. 672. Additionally, the transition described below is explained in the FAC-001-3
Mapping Document, attached herein as Exhibit J.
1.
Purpose and Overview of Proposed FAC-001-3
The purpose of proposed Reliability Standard FAC-001-3 is to “avoid adverse impacts on
the reliability of the Bulk Electric System” by requiring TOs and applicable GOs to “document
50
As noted above, NERC’s Proposal would retire current Requirement R7.
21
and make Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.” Along with the obligations on TOs and certain GOs to
ensure that all potential interconnecting parties have fair and unrestricted access to relevant
interconnection requirements, proposed Reliability Standard FAC-001-3 also captures a variety
of specific processes to ensure that entities take appropriate steps when interconnecting. For
example, the Reliability Standard requires TOs and GOs to address, in the interconnection
requirements, procedures for studies and analyses of interconnections and communication
regarding each facility interconnection.
Proposed Reliability Standard FAC-001-3 replaces and strengthens currently effective
Reliability Standard FAC-001-2 by moving currently effective Requirement R1 of Reliability
Standard BAL-005-0.2b to proposed FAC-001-3 thus requiring that TO and GO interconnection
requirements include procedures for confirming that new or materially modified Facilities
connecting to the BES are within a BAA’s metered boundaries. These interconnection
requirements should be relocated to Reliability Standard FAC-001-3, as FAC-001-3 establishes
Facility interconnection requirements.
2.
Applicability
The Requirements under proposed Reliability Standard FAC-001-3 continue to apply
only to TOs and Applicable GOs. As defined in Section 4.1 of currently effective FAC-001-2 and
proposed FAC-001-3 (attached as Exhibit B), an Applicable GO is defined as a “Generator
Owner with a fully executed Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission system.”
22
3.
Requirement-by-Requirement Justification
R3. Each Transmission Owner shall address the following items in its Facility interconnection
requirements: [Violation Risk Factor: Lower] [Time Horizon: Long-Term Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s) of
new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing Authority
Area’s metered boundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: Long-Term
Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
4.2. Procedures for notifying those responsible for the reliability of affected system(s) of
new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing Authority
Area’s metered boundaries.
NERC proposes to consolidate all interconnection requirements by moving Requirement
R1 of currently effective Reliability Standard BAL-005-0.2b to proposed Requirements R3.3 and
R4.4 of proposed FAC-001-3. As the purpose of FAC-001-3 is more commensurate with
interconnection responsibilities, interconnection procedures contained in currently effective
BAL-005-0.2b should be included in proposed Reliability Standard FAC-001-3. These
proposed revisions clarify that responsible entities must have interconnection procedures to
ensure that Facilities are within the metered boundaries of the BAA. Without these
Requirements, Facilities may be connected to the grid outside of a BAA, causing these Facilities
to be outside the scope of a BA’s resource plans, balancing calculations, and frequency control
oversight.
23
C.
Enforceability of Proposed Reliability Standards BAL-005-1 and FAC-001-3
Proposed Reliability Standards BAL-005-1 and FAC-001-3 include Measures to support
each Requirement to clarify necessary evidence or actions for compliance and to help ensure that
the Requirements will be enforced in a clear, consistent, non-preferential manner, and without
prejudice to any party. Proposed Reliability Standard BAL-005-1 includes seven Measures.
Proposed Reliability Standard FAC-001-3 includes four Measures. While inclusion of these
Measures associated with each Reliability Standard is consistent with the elements of a
Reliability Standard, 51 NERC developed the Measures for proposed Reliability Standard BAL005-1 in consideration of the Commission’s directive in Order No. 693 to revise the VRF for
Requirement R17 of BAL-005-0 to “Medium.” 52
Proposed Reliability Standards BAL-005-1 and FAC-001-3 also include VRFs and VSLs
for each Requirement. The VSLs and VRFs are part of several elements used to determine an
appropriate sanction when the associated Requirement is violated and each comports with the
NERC and Commission guidelines relate to their assignment. The VSLs provide guidance on
the way that NERC will enforce the Requirements of the proposed Reliability Standards. The
VRFs assess the impact to reliability of violating a specific Requirement and represent one of
several elements used to determine an appropriate sanction when the associated Requirement is
violated. All of the Requirements in proposed Reliability Standard BAL-005-1 have been
assigned a “Medium” VRF with a Time Horizon criterion of “Real-time Operations.” All of the
Requirements in proposed Reliability Standard FAC-001-3 have been assigned a “Lower” VRF
with a “Long-Term Planning” Time Horizon criterion. Exhibit G includes the detailed analysis
51
See, NERC Rules of Procedure, at Appendix 3A, at Section 2.5.
Order No. 693, supra n. 22, at P 58. NERC notes that, while currently effective Requirement R17 of BAL005-0.2b is proposed to be retired, part of that requirement is located in proposed Requirement R3 of BAL-005-1
and has been assigned a VRF of Medium.
52
24
of the assignment of VRFs and the VSLs for proposed Reliability Standards BAL-005-1 and
FAC-001-3. As described in that document, the VRFs and VSLs for the proposed Reliability
Standard comport with NERC and Commission guidelines. 53
D.
Proposed Retirement of Reliability Standard BAL-006-2
Currently effective Reliability Standard BAL-006-2 consists of five Requirements, each
applicable to BAs. In an ongoing effort to remove unnecessary Reliability Standards from its
suite of Reliability Standards, NERC proposes to retire four Requirements as “administrative in
nature” as defined in the Commission-approved Paragraph 81 Criteria. 54 As provided above,
NERC also proposes to move Requirement R3 to Reliability Standard BAL-005-1 because the
Requirement supports accurate Reporting ACE and falls squarely within the scope of BAL-0051. As NERC proposes to retire or move the Requirements in BAL-006-2 as explained in the
BAL-006-2 Mapping Document (Exhibit K), NERC proposes to retire BAL-006-2 in its
entirety.
1.
Overview
The purpose of currently effective Reliability Standard BAL-006-2 is to define “a process
for monitoring BAs to ensure that, over the long term, BAAs do not excessively depend on other
BAAs in the Interconnection for meeting their demand or Interchange obligations.” Aside from
the obligations in Requirement R3 of BAL-006-2, which have been moved to proposed BAL005-1 as described below, the SDT determined that each of the remaining Requirements in BAL006-2 are energy accounting standards and should be retired as “administrative” pursuant to
53
See, e.g., N. Am. Elec. Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120
FERC ¶ 61,145 (2007).
54
Paragraph 81 Criteria, supra n. 7 at Exhibit A (proposing to retire standards as “Administrative” if the
“Reliability Standard requirement requires responsible entities to perform a function that is administrative in nature,
does not support reliability and is needlessly burdensome.”); Order No. 788, supra n. 7.
25
Criteria B1 of the Commission approved Paragraph 81 Criteria. 55 The purpose of BAL-006-2,
excerpted above, describes a commercial practice that addresses inadvertent balances. This
purpose continues to be fulfilled by entities as described in the Inadvertent Interchange
Guideline, currently under review by the NERC OC.
In approving BAL-006 in Order No. 693, the Commission directed NERC “to develop a
modification to BAL-006-1 that adds Measures concerning the accumulation of large inadvertent
imbalances and Levels of Non-Compliance,” because “large imbalances represent dependence
by some balancing authorities on their neighbors and are an indication of less than desirable
balancing of generation with load.” 56 Further, the Commission stated that “large interchange
imbalances are indicative of an underlying problem related to balancing of resources and
demand,” and “[s]ince the ERO indicates that the reliability aspects of this issue will be
addressed in a Reliability Standards filing later this year, the Commission asks the ERO, when
filing the new Reliability Standard, to explain how the new Reliability Standard satisfies the
Commission’s concerns.” 57
The SDT solicited feedback from industry regarding the disposition of BAL-006-2 and
eventually determined that the calculation of Inadvertent Interchange is an accounting process
and is not appropriate for a NERC Reliability Standard. During periods when the Reporting
ACE of a BA is negatively affecting the Interconnection frequency beyond a predefined bound,
Reliability Standard BAL-001-2 requires BAs to maintain its clock-minute ACE within the
Balancing Authority ACE Limit (“BAAL”). Reliability Standard BAL-001-2 also requires
entities to take a rolling 12-month measure of overall control performance using clock-minute
55
56
57
Id.
Order No. 693, supra n. 22, at P 428.
Id. at P 438.
26
performance data. To further support frequency, Reliability Standard BAL-003-1 and proposed
Reliability Standard BAL-002-2 require entities to restore of Reporting ACE within predefined
bounds and to maintain and dispatch Frequency Response, as necessary. 58 These “real-time”
measures of control performance require entities to maintain Interconnection frequency, limiting
operation when it is detrimental to Interconnection frequency and encouraging operation when in
support of Interconnection frequency. Because entities are supporting frequency through this
coordinated suite of reliability standards, entities will not excessively depend on other entities in
the Interconnection such that the purely economic issue that was addressed by BAL-006-2
becomes a reliability issue for a NERC Reliability Standard.
As further support for this retirement, the SDT provided an in-depth justification for why
a NERC Reliability Standard is not necessary for Inadvertent Interchange accounting in its
Inadvertent Interchange White Paper. The Inadvertent Interchange White Paper was posted for
10 days for industry input on September 16, 2015 and was the basis for creation of the
Inadvertent Interchange Guideline. In order to address any remaining or potential concerns with
retirement of BAL-006-2, NERC proposes that the retirement of currently effective BAL-006-2
be effectuated upon the NERC OC approval of the Inadvertent Interchange Guideline. 59
58
See, .e.g, Petition of the North American Electric Reliability Corporation for Approval of Proposed
Reliability Standard BAL-002-2, Docket No. RM16-7-000 (filed Jan. 29, 2016); Clarifying Supplemental
Information for Petition for Approval of BAL-002-2, Docket No. RM16-7-000 (filed Feb. 12, 2016); Supplemental
Information for Petition of the North American Electric Reliability Corporation for Approval Of Proposed
Reliability Standard BAL-002-2, Docket No. RM16-7-000 (filed Mar. 31, 2016).
59
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines are usually sponsored by a NERC committee and are made available for industry comment
prior to finalization. The concepts in guidelines may be adopted by a Responsible Entity in accordance with its own
facts and circumstances.
27
2.
Requirement-by-Requirement Retirement Justification
a)
Requirements R1, R2, R4, and R5
The SDT proposes to retire Requirements R1, R2, R4, and R5, as these requirements are
“administrative” in nature based on the Commission-approved Paragraph 81 Criteria B1. 60
However, because large and long-held Inadvertent Interchange accumulations may impact
commercial relationships, and because the related paybacks can create impacts to reliability if
not conducted in an appropriate manner, the SDT also developed an Inadvertent Interchange
White Paper to define typical practices for isolating and eliminating sources of Inadvertent
accounting errors. The SDT and the OC Resources Subcommittee developed the Inadvertent
Interchange Guideline based on the evidence presented in the Inadvertent Interchange White
Paper. As described above, the Inadvertent Interchange Guideline is currently under review by
the OC.
Pursuant to NERC’s Paragraph 81 Criteria, a requirement may be retired if it “requires
responsible entities (“entities”) to conduct an activity or task that does little, if anything, to
benefit or protect the reliable operation of the BES,” and it meets another one of the criteria
described in Criteria B of that document. 61 One of those criteria, Criteria B1 (Administrative),
states that a Reliability Standard requirement may be retired if it “requires responsible entities to
perform a function that is administrative in nature, does not support reliability and is needlessly
burdensome.” 62 Criteria B1 also states that it is
designed to identify requirements that can be retired or modified with little effect on
reliability and whose retirement or modification will result in an increase in the efficiency
of the ERO compliance program…Strictly administrative functions do not inherently
negatively impact reliability directly and, where possible, should be eliminated or
60
61
62
Paragraph 81 Criteria, supra n. 6 at Exhibit A.
Id.
Id.
28
modified for purposes of efficiency and to allow the ERO and entities to appropriately
allocate resources. 63
The draft Inadvertent Interchange Guideline explains the relationship between
Inadvertent Interchange and reliability, current industry account practices to calculate and
compensate for Inadvertent Interchange, and options for potential commercial accounting
standards. As explained in the draft Inadvertent Interchange Guideline, the calculation
requirements in Requirements R1, R2, R4, and R5 of BAL-006-2 are commercial energy
accounting requirements and do not contribute to Reliable Operation of the BES. For example,
Inadvertent Interchange generally occurs because of a variety of factors, including accounting
errors such as bilateral or unilateral Inadvertent payback, false schedules implemented to correct
a perceived metering error, hourly interchange calculations that do not compensate for ramps, or
minor calculation errors. Balancing Authority Areas routinely monitor and account for
Inadvertent Interchange using standard accounting procedures. 64 If the Requirements of
proposed Reliability Standard BAL-005-1 are met, responsible entities will have all data
necessary to calculate Reporting ACE and will avoid potential reliability issues caused by
Inadvertent Interchange. The remaining issues associated with Inadvertent Interchange
accumulations are commercial issues and may be addressed as such. As such, Requirements R1,
R2, R4, and R5 should be retired as administrative under Criteria B1.
a)
Requirement R3
Requirement R3 of currently effective Reliability Standard BAL-006-2 has been moved
to proposed Requirement R7 of BAL-005-1. See supra, discussion at Section IV.A.3.g above.
63
Id.
Certain procedures followed by BAAs may be based on standard accounting practices, compliance with
NAESB Standard WEQ-007 Business Practice Requirements (Inadvertent Interchange Payback) (this standard only
accounts for the payback of Inadvertent Interchange), or other accounting rules.
64
29
E.
Proposed NERC Glossary Definitions
The SDT developed several new and modified NERC Glossary definitions in connection
with proposed Reliability Standards BAL-005-1 and FAC-001-3 to enhance the effectiveness of
those Standards in maintaining reliability. Specifically, NERC proposes new and modified
definitions of the following terms: Automatic Generation Control, Actual Frequency, Actual Net
Interchange, Scheduled Net Interchange, Interchange Meter Error, Automatic Time Error
Correction, Reporting ACE, Pseudo-Tie, and Balancing Authority.
With respect to the Commission’s directive in Order No. 693 regarding modification to
the definition of Operating Reserves, 65 NERC developed Reliability Standard BAL-002-2 and
associated proposed revisions to the definition of Contingency Reserve (now pending before the
Commission) to ensure a continent-wide, technology neutral reserve policy. 66 The proposed
revised definitions below are also technology neutral. NERC has removed the term Operating
Reserve in the BAL Reliability Standards and has developed an Operating Reserve Guideline to
help address any remaining potential concerns. As a result, NERC’s Proposal addresses
remaining directives regarding terms used in the BAL Reliability Standards.
1.
Automatic Generation Control
Automatic Generation Control (AGC): Equipment that automatically adjusts generation
in a Balancing Authority Area from a central location to maintain the Balancing
Authority’s interchange schedule plus Frequency Bias. AGC may also accommodate
automatic inadvertent payback and time error correction. A process designed and used to
automatically adjust a Balancing Authority Areas’ Demand and/or resources to help maintain
the Reporting ACE in that of a Balancing Authority Area within the bounds required by
applicable NERC Reliability Standards.
65
Order No. 693, supra n. 22, at P 1896; see also, id. supra n. 22, at PP 336, 340, 343-344, 405, 1887
(providing additional clarity regarding the directed revisions).
66
Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability
Standard BAL-002-2, supra n. 57, at pp. 3-4, 15-16, and Contingency Event Standard Background Document (Jan.
29, 2016).
30
The definition of Automatic Generation Control describes the process by which an entity
controls its Reporting ACE in Reliability Standard BAL-005-1. This definition has been revised
as shown to reflect modernization of the industry and to set forth a resource-neutral process for
controlling demand and resources. The proposed definition allows the entity the flexibility to
perform necessary reliability functions in the most effective and reliable manner.
2.
Reporting ACE
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) – IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) – IME + IATEC
Where:
Actual Net Interchange.
• NIA =
• NIS
=
Scheduled Net Interchange.
• B
=
Frequency Bias Setting.
• FA
=
Actual Frequency.
• FS
=
Scheduled Frequency.
=
Interchange Meter Error.
• IME
• IATEC =
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie Line Bias (TLB) Control
and require the use of an ACE equation similar to the Reporting ACE defined above. Any
modification(s) to this specified Reporting ACE equation that is(are) implemented for all
BAAs on an Interconnection and is(are) consistent with the following four principles of
Tie Line Bias control will provide a valid alternative to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency FS for all BAAs at all times; and,
31
4. Excludes metering or computational errors. (The inclusion and use of the IME term
corrects for known metering or computational errors.)
The currently effective definition of Reporting ACE defines several components used to
calculate Reporting ACE. The revised, proposed definition of Reporting ACE is clearer because
it includes only the Reporting ACE calculation. NERC’s Proposal would separately define each
of the components used to calculate Reporting ACE as discussed immediately below.
3.
Components of Reporting ACE
Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers across all
Tie Lines, including Pseudo‐Ties, to and from all Adjacent Balancing Authority areas
within the same Interconnection. Actual megawatt transfers on asynchronous DC tie lines
that are directly connected to another Interconnection are excluded from Actual Net
Interchange.
Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to another
Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (IME): A term, normally zero, used in the Reporting ACE
calculation to compensate for data or equipment errors affecting any other components of
the Reporting ACE calculation.
Automatic Time Error Correction (IATEC): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the purpose
of continuously paying back Primary Inadvertent Interchange to correct accumulated time
error. Automatic Time Error Correction is only applicable in the Western
Interconnection.
I𝑨𝑨𝑨𝑨𝑨𝑨𝑨𝑨 =
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐 𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
(𝟏𝟏−𝒀𝒀)∗𝑯𝑯
when operating in Automatic Time Error Correction Mode.
The absolute value of IATEC shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
•
•
Lmax is the maximum value allowed for IATEC set by each BA between 0.2*|Bi|
and L10, 0.2*|Bi|≤ Lmax ≤ L10 .
L10 = 1.65 ∗ ε10 �(−10Bi )(−10BS ) .
32
•
•
•
•
•
•
•
•
•
•
•
10 is a constant derived from the targeted frequency bound. It is the targeted
root-mean-square (RMS) value of ten-minute average frequency error based on
frequency performance over a given year. The bound, 1
0, is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy.
The value of H is set to 3.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW
/ 0.1 Hz).
Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - Bi * ΔTE/6)
IIactual is the hourly Inadvertent Interchange for the last hour. ΔTE is the hourly
change in system Time Error as distributed by the Interconnection time
monitor,where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)
TDadj is the Reliability Coordinator adjustment for differences with
Interconnection time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during
the hour.
TEoffset is 0.000 or +0.020 or -0.020.
PIIaccum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An OnPeak and Off-Peak accumulation accounting is required,
where:
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
= 𝒍𝒍𝒍𝒍𝒍𝒍𝒍𝒍 𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒅𝒅′ 𝒔𝒔 PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
+ PII𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉
As explained above, NERC’s Proposal moves the components of Reporting ACE from
that term to separate NERC Glossary terms. This separation will improve reliability by reducing
potential confusion associated with definitions embedded within a term. The proposed definition
of ATEC also improves the current definition by addressing a Commission directive.
Specifically, the proposed definition addresses the Commission’s directive in Order No. 810 for
NERC to “revise the definition of Reporting ACE to include the ‘Lmax’ upper payback limit and
the bounds of that upper payback limit prior to the effective date of Reliability Standard BAL001-1.” 67 The proposed definition of ATEC, which is incorporated into the proposed definition
67
Order No. 810, supra n. 9. The Commission also explained that the Lmax upper payback limit and the
bounds of that limit were necessary for the Western Interconnection.
33
of Reporting ACE (as explained above) and is only applicable in the Western Interconnection,
states that “[t]he absolute value of IATEC shall not exceed Lmax.”
4.
Pseudo-Tie
Pseudo-Tie: A time-varying energy transfer that is updated in Real-time and included in
the Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected
Balancing Authorities’ control Reporting ACE equation (or alternate control processes).
The proposed definition of the term Pseudo-Tie has been updated to reflect the use of the
term “Reporting ACE” instead of the more general “control ACE.” The proposed definition is
clearer and reduces confusion associated with outdated terminology.
5.
Balancing Authority
Balancing Authority: The responsible entity that integrates resource plans ahead of
time, maintains load-interchange-generation balance Demand and resource balance
within a Balancing Authority Area, and supports Interconnection frequency in real time.
To ensure consistency with the proposed definition of AGC, the SDT revised the
definition of a BA to more accurately describe the BA’s resource demand function. The standard
drafting team for Project 2015-04 (Alignment of Terms) also highlighted inconsistent use of the
term "load-interchange-generation" and recommended that an open BAL Standard project
address the issue. Therefore, the proposed changes promote clarity and consistency with other
definitions and with various Reliability Standards.
V.
EFFECTIVE DATE
NERC respectfully requests that the Commission accept proposed Reliability Standards
BAL-005-1 and FAC-001-3 on the first day of the first calendar quarter that is 12 months after
appropriate governmental approval, pursuant to the respective Implementation Plans in Exhibits
D and E of this Petition. In addition, NERC requests that that the Commission approve
retirement of Reliability Standard BAL-006-2 upon the effective date of Reliability Standard
34
BAL-005-1 and the OC’s approval of an Inadvertent Interchange Guideline, as stated in the
Implementation Plan attached at Exhibit F. 68 NERC also requests that the proposed definitions
for the definitions of Reporting ACE, Actual Frequency, Actual Net Interchange, Schedule Net
Interchange, Interchange Meter Error, and ATEC become effective immediately after the July 1,
2016 effective date of Reliability Standard BAL-001-2 to ensure proper coordination the
proposed definitions and Commission approved Reliability Standard BAL-001-2. 69 Finally,
NERC requests that the proposed definitions for AGC, Pseudo-Tie, and Balancing Authority
become effective upon the effective date for Reliability Standard BAL-005-1. These effective
dates will ensure coordinated implementation of NERC’s proposed revisions, avoid reliability
gaps, and effect a seamless transition to NERC’s Proposal.
68
Supra n. 55.
See, BAL-005-1 Implementation Plan, attached hereto as Exhibit D. This Implementation Plan reflects the
SDT’s intent to supersede the “Reporting ACE” definition approved in Order No. 810, supra n. 9, P 43 (2015). As
explained above in note 8, the SDT intended that the definition of “Reporting ACE” approved in Order No. 810
never take effect. The definition of “Reporting ACE” approved in Order No. 810 may, however, be in effect for
some limited period of time while this Petition and the proposed definitions under NERC’s Proposal are pending
Commission review.
69
35
VI.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve
NERC’s Proposal regarding (i) proposed Reliability Standards BAL-005-1 and FAC-001-3,
proposed NERC Glossary Definitions, and other associated elements in Exhibits A and B (the
proposed NERC Glossary definitions are set forth in Exhibit D); (ii) the Implementation Plans
for BAL-005-1 and FAC-001-3 in Exhibits D, E, and F; (iii) the VRFs and VSLs in Exhibits G
and H; (iv) and retirement of currently effective Reliability Standards BAL-005-0.2b, FAC-0012, and BAL-006-2 (proposed retirement of BAL-006-2 is shown in Exhibit C).
Respectfully submitted,
/s/ Andrew C. Wills
Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
Candice Castaneda
Counsel
Andrew C. Wills
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: April 20, 2016
36
Exhibit A
Proposed Reliability Standard BAL-005-1
BAL-005-1 Clean Version
BAL-005-1 – Balancing Authority Control
A. Introduction
1.
Title:
Balancing Authority Control
2.
Number:
BAL-005-1
3.
Purpose: This standard establishes requirements for acquiring data necessary to
calculate Reporting Area Control Error (Reporting ACE). The standard also specifies a
minimum periodicity, accuracy, and availability requirement for acquisition of the
data and for providing the information to the System Operator.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Balancing Authority
Effective Date: See Implementation Plan for BAL-005-1
B. Requirements and Measures
R1.
The Balancing Authority shall use a design scan rate of no more than six seconds in
acquiring data necessary to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
M1. Each Balancing Authority will have dated documentation demonstrating that the data
necessary to calculate Reporting ACE was designed to be scanned at a rate of no more
than six seconds. Acceptable evidence may include historical data, dated archive files;
or data from other databases, spreadsheets, or displays that demonstrate
compliance.
R2.
A Balancing Authority that is unable to calculate Reporting ACE for more than 30consecutive minutes shall notify its Reliability Coordinator within 45 minutes of the
beginning of the inability to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
M2. Each Balancing Authority will have dated records to show when it was unable to
calculate Reporting ACE for more than 30 consecutive minutes and that it notified its
Reliability Coordinator within 45 minutes of the beginning of the inability to calculate
Reporting ACE. Such evidence may include, but is not limited to, dated voice
recordings, operating logs, or other communication documentation.
R3.
Each Balancing Authority shall use frequency metering equipment for the calculation
of Reporting ACE: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
3.1. that is available a minimum of 99.95% for each calendar year; and,
3.2. with a minimum accuracy of 0.001 Hz.
Page 1 of 11
BAL-005-1 – Balancing Authority Control
M3. The Balancing Authority shall have evidence such as dated documents or other
evidence in hard copy or electronic format showing the frequency metering
equipment used for the calculation of Reporting ACE had a minimum availability of
99.95% for each calendar year and had a minimum accuracy of 0.001 Hz to
demonstrate compliance with Requirement R3.
R4.
The Balancing Authority shall make available to the operator information associated
with Reporting ACE including, but not limited to, quality flags indicating missing or
invalid data. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
M4. Each Balancing Authority Area shall have evidence such as a graphical display or dated
alarm log that provides indication of data validity for the real-time Reporting ACE
based on both the calculated result and all of the associated inputs therein.
R5.
Each Balancing Authority’s system used to calculate Reporting ACE shall be available a
minimum of 99.5% of each calendar year. [Violation Risk Factor: Medium] [Time
Horizon: Operations Assessment]
M5. Each Balancing Authority will have dated documentation demonstrating that the
system necessary to calculate Reporting ACE has a minimum availability of 99.5% for
each calendar year. Acceptable evidence may include historical data, dated archive
files; or data from other databases, spreadsheets, or displays that demonstrate
compliance.
R6.
Each Balancing Authority that is within a multiple Balancing Authority Interconnection
shall implement an Operating Process to identify and mitigate errors affecting the
accuracy of scan rate data used in the calculation of Reporting ACE for each Balancing
Authority Area. [Violation Risk Factor: Medium] [Time Horizon: Same-day Operations]
M6. Each Balancing Authority shall have a current Operating Process meeting the
provisions of Requirement R6 and evidence to show that the process was
implemented, such as dated communications or incorporation in System Operator
task verification.
R7.
Each Balancing Authority shall ensure that each Tie-Line, Pseudo-Tie, and Dynamic
Schedule with an Adjacent Balancing Authority is equipped with: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
7.1. a common source to provide information to both Balancing Authorities for the
scan rate values used in the calculation of Reporting ACE; and,
7.2. a time synchronized common source to determine hourly megawatt-hour values
agreed-upon to aid in the identification and mitigation of errors.
M7. The Balancing Authority shall have dated evidence such as voice recordings or
transcripts, operator logs, electronic communications, or other equivalent evidence
that will be used to demonstratea common source for the components used in the
calculation of Reporting ACE with its Adjacent Balancing Authority.
Page 2 of 11
BAL-005-1 – Balancing Authority Control
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention period(s) identify the period of time an
entity is required to retain specific evidence to demonstrate compliance. For
instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask
an entity to provide other evidence to show that it was compliant for the fulltime period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
The applicable entity shall keep data or evidence to show compliance for
the current year, plus three previous calendar years.
1.3. Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will
be used to evaluate data or information for the purpose of assessing
performance or outcomes with the associated Reliability Standard.
1.4. Additional Compliance Information
None
Page 3 of 11
BAL-005-1 – Balancing Authority Control
Table of Compliance Elements
R#
Time
Horizon
VRF
R1.
Real-time
Operations
R2.
Real-time
Operations
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
Medium
N/A
N/A
N/A
Balancing Authority
was using a design
scan rate of greater
than six seconds to
acquire the data
necessary to calculate
Reporting ACE.
Medium
The Balancing
Authority failed to
notify its Reliability
Coordinator within
45 minutes of the
beginning of the
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 50
minutes from the
beginning of the
The Balancing
Authority failed to
notify its Reliability
Coordinator within 50
minutes of the
beginning of an
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 55
minutes from the
beginning of an
The Balancing
Authority failed to
notify its Reliability
Coordinator within
55 minutes of the
beginning of an
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 60
minutes from the
beginning of an
The Balancing
Authority failed to
notify its Reliability
Coordinator within 60
minutes of the
beginning of an
inability to calculate
Reporting ACE.
Page 4 of 11
BAL-005-1 – Balancing Authority Control
R3.
R4.
Real-time
Operations
Real-time
Operations
Medium
Medium
inability to calculate
Reporting ACE.
inability to calculate
Reporting ACE.
inability to calculate
Reporting ACE.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.95% of the
calendar year but
was available greater
than or equal to
99.94 % of the
calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.94% of the
calendar year but was
available greater than
or equal to 99.93 % of
the calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.93% of the
calendar year but
was available greater
than or equal to
99.92 % of the
calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.92% of the
calendar year
N/A
N/A
N/A
The Balancing
Authority failed to
make available
information
indicating missing or
invalid data
associated with
Or
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE failed
to have a minimum
accuracy of 0.001 Hz.
Page 5 of 11
BAL-005-1 – Balancing Authority Control
Reporting ACE to its
operators.
R5.
Operations
Assessment
Medium
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.5% of the calendar
year but was
available greater
than or equal to 99.4
% of the calendar
year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.4% of the calendar
year but was
available greater than
or equal to 99.3 % of
the calendar year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.3% of the calendar
year but was
available greater
than or equal to 99.2
% of the calendar
year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.2% of the calendar
year.
R6.
Same-day
Operations
Medium
N/A
N/A
N/A
The Balancing
Authority failed to
implement an
Operating Process to
identify and mitigate
errors affecting the
scan-rate accuracy of
data used in the
calculation of
Reporting ACE.
R7.
Operations
Planning
Medium
N/A
N/A
N/A
The Balancing
Authority failed to
use a common source
for Tie-Lines, Pseudoties and Dynamic
Page 6 of 11
BAL-005-1 – Balancing Authority Control
Schedules with its
Adjacent Balancing
Authorities
Or
The Balancing
Authority failed to
use a time
synchronized
common source for
hourly megawatt
hour values that are
agreed-upon to aid in
the identification and
mitigation of errors.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.
Page 7 of 11
BAL-005-1 – Balancing Authority Control
Version History
Version
Date
Action
Change Tracking
0
February 8,
2005
Adopted by NERC Board of Trustees
New
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
0a
December 19,
2007
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Addition
0a
January 16,
2008
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Errata
0b
February 12,
2008
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Replacement
0.1b
October 29,
2008
BOT approved errata changes; updated version
number to “0.1b”
Errata
0.1b
May 13, 2009
FERC approved – Updated Effective Date
Addition
0.2b
March 8, 2012
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
Errata
0.2b
September 13,
2012
FERC approved – Updated Effective Date
Addition
Page 8 of 11
BAL-005-1 – Balancing Authority Control
0.2b
February 7,
2013
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
0.2b
November 21,
2013
R2 and associated elements approved by FERC for
retirement as part of the Paragraph 81 project
(Project 2013-02) effective January 21, 2014.
February 11,
2016
Adopted by NERC Board of Trustees
1
Complete re-write of standard
Page 9 of 11
Supplemental Material
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon Board approval, the text from the
rationale boxes will be moved to this section.
Rationale for Requirement R1: Real-time operation of a Balancing Authority requires real-time
information. A sufficient scan rate is key to an Operator’s trust in real-time information.
Without a sufficient scan rate, an operator may question the accuracy of data during events,
which would degrade the operator’s ability to maintain reliability.
Rationale for Requirement R2: The RC is responsible for coordinating the reliability of bulk
electric systems for member BA’s. When a BA is unable to calculate its ACE for an extended
period of time, this information must be communicated to the RC within 15 minutes thereafter
so that the RC has sufficient knowledge of system conditions to assess any unintended
reliability consequences that may occur on the wide area.
Rationale for Requirement R3: Frequency is the basic measurement for interconnection health,
and a critical component for calculating Reporting ACE. Without sufficient available frequency
data the BA operator will lack situational awareness and will be unable to make correct
decisions when maintaining reliability.
Rationale for Requirement R4: System operators utilize Reporting ACE as a primary metric to
determine operating actions or instructions. When data inputs into the ACE calculation are
incorrect, the operator should be made aware through visual display. When an operator
questions the validity of data, actions are delayed and the probability of adverse events
occurring can increase.
Rationale for Requirement R5: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Since Reporting ACE is a measure of the
BA’s reliability performance for BAL-001, and BAL-002, it is critical that Reporting ACE be
sufficiently available to assure reliability.
Rationale for Requirement R6: Reporting ACE is a measure of the BA’s reliability performance
for BAL-001, and BAL-002. Without a process to address persistent errors in the ACE calculation,
the operator can lose trust in the validity of Reporting ACE resulting in delayed or incorrect
decisions regarding the reliability of the bulk electric system.
Rationale for Requirement R7: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Common source data is critical to
calculating Reporting ACE that is consistent between Balancing Authorities. When data sources
are not common, confusion can be created between BAs resulting in delayed or incorrect
operator action.
Page 10 of 11
Supplemental Material
The intent of Requirement R7 Part 7.1 is to provide accuracy in the measurement and
calculations used in Reporting ACE. It specifies the need for common metering points for
instantaneous values for the tie-line megawatt flow values between Balancing Authority Areas.
Common data source requirements also apply to instantaneous values for pseudo-ties and
dynamic schedules, and can extend to more than two Balancing Authorities that participate in
allocating shares of a generation resource in supplementary regulation, for example.
The intent of Requirement R7 Part 7.2 is to enable accuracy in the measurements and
calculations used in Reporting ACE. It specifies the need for common metering points for
hourly accumulated values for the time synchronized tie line MWh values agreed-upon
between Balancing Authority Areas. These time synchronized agreed-upon values are
necessary for use in the Operating Process required in R6 to identify and mitigate errors in the
scan-rate values used in Reporting ACE.
Page 11 of 11
BAL-005-1 Redline Version
BAL-005-1 – Balancing Authority Control
A. Introduction
1.
Title:
Automatic Generation Balancing Authority Control
2.
Number:
BAL-005-0.2b1
3.
Purpose: This standard establishes requirements for Balancing Authority
Automatic Generation Control (AGC)acquiring data necessary to calculate Reporting
Area Control Error (Reporting ACE) and to routinely deploy the Regulating Reserve.).
The standard also ensures that all facilitiesspecifies a minimum periodicity, accuracy,
and availability requirement for acquisition of the data and load electrically
synchronized tofor providing the Interconnection are included within information to
the metered boundary of a Balancing Area so that balancing of resources and demand
can be achievedSystem Operator.
4.
Applicability:
4.1. Balancing Authorities
4.2.
Generator Operators
4.3.
Transmission Operators
4.4.4.1.
Load ServingFunctional Entities:
4.1.1. Balancing Authority
5.
Effective Date:
May 13, 2009 See Implementation Plan for BAL-
005-1
B.
Requirements
R1.B.
All generation, transmission, and load operating within an
Interconnection must be included within the metered boundaries of a
Balancing Authority Area.Measures
R1.1. The Balancing Each Generator Operator with generation facilities operating in
an Interconnection shall ensure that those generation facilities are included
within the metered boundaries of a Balancing Authority Area.
R1.2. Each Transmission Operator with transmission facilities operating in an
Interconnection shall ensure that those transmission facilities are included
within the metered boundaries of a Balancing Authority Area.
R1.3. Each Load-Serving Entity with load operating in an Interconnection shall
ensure that those loads are included within the metered boundaries of a
Balancing Authority Area.
R2. Each Balancing Authority shall maintain Regulating Reserve that can be controlled by
AGC to meet the Control Performance Standard. (Retirement approved by FERC
effective January 21, 2014.)
Page 1 of 17
BAL-005-1 – Balancing Authority Control
R1.
Authority shall use a design scan rate of no more than six seconds in acquiring data
necessary to calculate Reporting ACE. [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations]
M1. Each Balancing Authority will have dated documentation demonstrating that the data
necessary to calculate Reporting ACE was designed to be scanned at a rate of no more
than six seconds. Acceptable evidence may include historical data, dated archive files;
or data from other databases, spreadsheets, or displays that demonstrate
compliance.
R3. A Balancing Authority providing Regulation Service shall ensure that adequate
metering, communications, and control equipment are employed to prevent such
service from becoming a Burden on the Interconnection or other Balancing Authority
Areas.
R4. A Balancing Authority providing Regulation Service shall notify the Host Balancing
Authority for whom it is controlling if it that is unable to provide the service, as well
as any Intermediate Balancing Authorities.
R5.
A Balancing Authority receiving Regulation Service shall ensure that backup plans are
in place to provide replacement Regulation Service should the supplying Balancing
Authority no longer be able to provide this service.calculate Reporting ACE for more
than 30-consecutive
R6.R2.
The Balancing Authority’s AGC shall compare total Net Actual Interchange to
total Net Scheduled Interchange plus Frequency Bias obligation to determine the
Balancing Authority’s ACE. Single Balancing Authorities operating asynchronously
may employ alternative ACE calculations such as (but not limited to) flat frequency
control. If a Balancing Authority is unable to calculate ACE for more than 30 minutes
it shall notify its Reliability Coordinator. within 45 minutes of the beginning of the
inability to calculate Reporting ACE. [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations]
M2. Each Balancing Authority will have dated records to show when it was unable to
calculate Reporting ACE for more than 30 consecutive minutes and that it notified its
Reliability Coordinator within 45 minutes of the beginning of the inability to calculate
Reporting ACE. Such evidence may include, but is not limited to, dated voice
recordings, operating logs, or other communication documentation.
R3.
Each Balancing Authority shall use frequency metering equipment for the calculation
of Reporting ACE: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
3.1. that is available a minimum of 99.95% for each calendar year; and,
3.2. with a minimum accuracy of 0.001 Hz.
R7. The Balancing Authority shall operate AGC continuously unless such operation
adversely impacts the reliability of the Interconnection. If AGC has become
Page 2 of 17
BAL-005-1 – Balancing Authority Control
inoperative, the Balancing Authority shall use manual control to adjust generation to
maintain the Net Scheduled Interchange.
R8. The Balancing Authority shall ensure that data acquisition for and calculation of ACE
occur at least every six seconds.
R8.1.M3. Each Balancing Authority shall provide redundant and independent have
evidence such as dated documents or other evidence in hard copy or electronic
format showing the frequency metering equipment that shall automatically activate
upon detection of failure of the primary source. This overall installation shall
provideused for the calculation of Reporting ACE had a minimum availability of
99.95%.% for each calendar year and had a minimum accuracy of 0.001 Hz to
demonstrate compliance with Requirement R3.
R4.
The Balancing Authority shall make available to the operator information associated
with Reporting ACE including, but not limited to, quality flags indicating missing or
invalid data. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
M4. Each Balancing Authority Area shall have evidence such as a graphical display or dated
alarm log that provides indication of data validity for the real-time Reporting ACE
based on both the calculated result and all of the associated inputs therein.
R5.
Each Balancing Authority’s system used to calculate Reporting ACE shall be available a
minimum of 99.5% of each calendar year. [Violation Risk Factor: Medium] [Time
Horizon: Operations Assessment]
M5. Each Balancing Authority will have dated documentation demonstrating that the
system necessary to calculate Reporting ACE has a minimum availability of 99.5% for
each calendar year. Acceptable evidence may include historical data, dated archive
files; or data from other databases, spreadsheets, or displays that demonstrate
compliance.
R6.
Each Balancing Authority that is within a multiple Balancing Authority Interconnection
shall implement an Operating Process to identify and mitigate errors affecting the
accuracy of scan rate data used in the calculation of Reporting ACE for each Balancing
Authority Area. [Violation Risk Factor: Medium] [Time Horizon: Same-day Operations]
M6. Each Balancing Authority shall have a current Operating Process meeting the
provisions of Requirement R6 and evidence to show that the process was
implemented, such as dated communications or incorporation in System Operator
task verification.
R7.
Each Balancing Authority shall ensure that each Tie-Line, Pseudo-Tie, and Dynamic
Schedule with an Adjacent Balancing Authority is equipped with: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
7.1. a common source to provide information to both Balancing Authorities for the
scan rate values used in the calculation of Reporting ACE; and,
7.2. a time synchronized common source to determine hourly megawatt-hour values
agreed-upon to aid in the identification and mitigation of errors.
Page 3 of 17
BAL-005-1 – Balancing Authority Control
R9. The Balancing Authority shall include all Interchange Schedules with Adjacent
Balancing Authorities in the calculation of Net Scheduled Interchange for the ACE
equation.
R9.1. Balancing Authorities with a high voltage direct current (HVDC) link to
another Balancing Authority connected asynchronously to their Interconnection
may choose to omit the Interchange Schedule related to the HVDC link from
the ACE equation if it is modeledhave dated evidence such as internal
generation or load.
R10. The Balancing Authority shall include all Dynamic Schedules in the calculation of Net
Scheduled Interchange for the ACE equation.
R11. Balancing Authorities shall include the effect of ramp rates, which shall be identical
and agreed to between affected Balancing Authorities,voice recordings or transcripts,
operator logs, electronic communications, or other equivalent evidence that will be
used to demonstrate a common source for the components used in the Scheduled
Interchange values to calculate ACE.
R12.M7.
Each Balancing Authority shall include all Tie Line flowscalculation of Reporting
ACE with its Adjacent Balancing Authority Areas in the ACE calculation.
R12.1. Balancing Authorities that share a tie shall ensure Tie Line MW metering is
telemetered to both control centers, and emanates from a common, agreed-upon
source using common primary metering equipment. Balancing Authorities
shall ensure that megawatt-hour data is telemetered or reported at the end of
each hour.
R12.2. Balancing Authorities shall ensure the power flow and ACE signals that are
utilized for calculating Balancing Authority performance or that are transmitted
for Regulation Service are not filtered prior to transmission, except for the Antialiasing Filters of Tie Lines.
R12.3. Balancing Authorities shall install common metering equipment where
Dynamic Schedules or Pseudo-Ties are implemented between two or more
Balancing Authorities to deliver the output of Jointly Owned Units or to serve
remote load.
R13. Each Balancing Authority shall perform hourly error checks using Tie Line megawatt-
hour meters with common time synchronization to determine the accuracy of its
control equipment. The Balancing Authority shall adjust the component (e.g., Tie
Line meter) of ACE that is in error (if known) or use the interchange meter error (IME)
term of the ACE equation to compensate for any equipment error until repairs can be
made.
R14. The Balancing Authority shall provide its operating personnel with sufficient
instrumentation and data recording equipment to facilitate monitoring of control
performance, generation response, and after-the-fact analysis of area performance. As
a minimum, the Balancing Authority shall provide its operating personnel with realtime values for ACE, Interconnection frequency and Net Actual Interchange with each
Adjacent Balancing Authority Area.
Page 4 of 17
BAL-005-1 – Balancing Authority Control
R15. The Balancing Authority shall provide adequate and reliable backup power supplies
and shall periodically test these supplies at the Balancing Authority’s control center
and other critical locations to ensure continuous operation of AGC and vital data
recording equipment during loss of the normal power supply.
R16. The Balancing Authority shall sample data at least at the same periodicity with which
ACE is calculated. The Balancing Authority shall flag missing or bad data for
operator display and archival purposes. The Balancing Authority shall collect
coincident data to the greatest practical extent, i.e., ACE, Interconnection frequency,
Net Actual Interchange, and other data shall all be sampled at the same time.
R17. Each Balancing Authority shall at least annually check and calibrate its time error and
frequency devices against a common reference. The Balancing Authority shall adhere
to the minimum values for measuring devices as listed below:
C.
Device
Accuracy
Digital frequency transducer
≤ 0.001
MW, MVAR, and voltage transducer
≤ 0.25 % of full scale
Remote terminal unit
≤ 0.25 % of full scale
Potential transformer
≤ 0.30 % of full scale
Current transformer
≤ 0.50 % of full scale
Hz
Measures
Not specified.
Page 5 of 17
BAL-005-1 – Balancing Authority Control
D.C.
1.
Compliance
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
Balancing Authorities shall be prepared to supply data to NERC in the format
defined below:
1.1.1.
Within one week upon request, Balancing Authorities shall provide As
defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Reliability Organization CPS
source data Entity in daily CSV filestheir respective roles of
monitoring and enforcing compliance with time stamped one minute
averages of: 1) ACE and 2) Frequency Error.
Within one week upon request, Balancing Authorities shall provide
the NERC or the Regional Reliability Organization DCS source data in CSV
files with time stamped scan rate values for: 1) ACE and 2) Frequency Error
for a time period of two minutes prior to thirty minutes after the identified
DisturbanceReliability Standards.
1.1.2.
1.2.
Compliance Monitoring Period and Reset Timeframe
Not specified.
1.3.1.2. DataEvidence Retention
1.3.1. Each Balancing Authority shall retain its ACE, actual frequency,
Scheduled Frequency, Net Actual Interchange, Net Scheduled
Interchange, Tie Line meter error correction and Frequency Bias
Setting data in digital format at the same scan rate at which the data is
collected for at least one year.
1.3.2.
Each Balancing Authority or Reserve Sharing Group shall retain
documentation of the magnitude of each Reportable Disturbance as
well as the ACE charts and/or samples used to calculate Balancing
Authority or Reserve Sharing Group disturbance recovery values. The
data shall be retained for one year following the reporting quarter for
which the data was recorded.
The following evidence retention period(s) identify the period of time an
entity is required to retain specific evidence to demonstrate compliance. For
instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask
an entity to provide other evidence to show that it was compliant for the fulltime period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
Page 6 of 17
BAL-005-1 – Balancing Authority Control
•
The applicable entity shall keep data or evidence to show compliance for
the current year, plus three previous calendar years.
1.3. Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will
be used to evaluate data or information for the purpose of assessing
performance or outcomes with the associated Reliability Standard.
1.4. Additional Compliance Information
Not specified.
LevelsNone
Page 7 of 17
BAL-005-1 – Balancing Authority Control
Table of Non-Compliance Elements
2.
Not specified.
R#
Time
Horizon
VRF
R1.
Real-time
Operations
R2.
Real-time
Operations
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
Medium
N/A
N/A
N/A
Balancing Authority
was using a design
scan rate of greater
than six seconds to
acquire the data
necessary to calculate
Reporting ACE.
Medium
The Balancing
Authority failed to
notify its Reliability
Coordinator within
45 minutes of the
beginning of the
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 50
minutes from the
beginning of the
The Balancing
Authority failed to
notify its Reliability
Coordinator within 50
minutes of the
beginning of an
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 55
minutes from the
beginning of an
The Balancing
Authority failed to
notify its Reliability
Coordinator within
55 minutes of the
beginning of an
inability to calculate
Reporting ACE but
notified its Reliability
Coordinator in less
than or equal to 60
minutes from the
beginning of an
The Balancing
Authority failed to
notify its Reliability
Coordinator within 60
minutes of the
beginning of an
inability to calculate
Reporting ACE.
Page 8 of 17
BAL-005-1 – Balancing Authority Control
R3.
R4.
Real-time
Operations
Real-time
Operations
Medium
Medium
inability to calculate
Reporting ACE.
inability to calculate
Reporting ACE.
inability to calculate
Reporting ACE.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.95% of the
calendar year but
was available greater
than or equal to
99.94 % of the
calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.94% of the
calendar year but was
available greater than
or equal to 99.93 % of
the calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.93% of the
calendar year but
was available greater
than or equal to
99.92 % of the
calendar year.
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.92% of the
calendar year
N/A
N/A
N/A
The Balancing
Authority failed to
make available
information
indicating missing or
invalid data
associated with
Or
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE failed
to have a minimum
accuracy of 0.001 Hz.
Page 9 of 17
BAL-005-1 – Balancing Authority Control
Reporting ACE to its
operators.
R5.
Operations
Assessment
Medium
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.5% of the calendar
year but was
available greater
than or equal to 99.4
% of the calendar
year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.4% of the calendar
year but was
available greater than
or equal to 99.3 % of
the calendar year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.3% of the calendar
year but was
available greater
than or equal to 99.2
% of the calendar
year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.2% of the calendar
year.
R6.
Same-day
Operations
Medium
N/A
N/A
N/A
The Balancing
Authority failed to
implement an
Operating Process to
identify and mitigate
errors affecting the
scan-rate accuracy of
data used in the
calculation of
Reporting ACE.
R7.
Operations
Planning
Medium
N/A
N/A
N/A
The Balancing
Authority failed to
use a common source
for Tie-Lines, Pseudoties and Dynamic
Page 10 of 17
BAL-005-1 – Balancing Authority Control
Schedules with its
Adjacent Balancing
Authorities
Or
The Balancing
Authority failed to
use a time
synchronized
common source for
hourly megawatt
hour values that are
agreed-upon to aid in
the identification and
mitigation of errors.
E.D.
Regional DifferencesVariances
None.
E. Interpretations
NoneNone identified.
F. Associated Documents
1.
Appendix 1 Interpretation of Requirement R17 (February 12, 2008).
None.
Page 11 of 17
BAL-005-1 – Balancing Authority Control
Version History
Version
Date
Action
Change Tracking
0
February 8,
2005
Adopted by NERC Board of Trustees
New
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
0a
December 19,
2007
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Addition
0a
January 16,
2008
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Errata
0b
February 12,
2008
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Replacement
0.1b
October 29,
2008
BOT approved errata changes; updated version
number to “0.1b”
Errata
0.1b
May 13, 2009
FERC approved – Updated Effective Date
Addition
0.2b
March 8, 2012
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
Errata
0.2b
September 13,
2012
FERC approved – Updated Effective Date
Addition
Page 12 of 17
BAL-005-1 – Balancing Authority Control
0.2b
February 7,
2013
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
0.2b
November 21,
2013
R2 and associated elements approved by FERC for
retirement as part of the Paragraph 81 project
(Project 2013-02) effective January 21, 2014.
February 11,
2016
Adopted by NERC Board of Trustees
1
Complete re-write of standard
Appendix 1
Effective Date: August 27, 2008 (U.S.)
Interpretation of BAL-005-0 Automatic Generation Control, R17
Request for Clarification received from PGE on July 31, 2007
PGE requests clarification regarding the measuring devices for which the requirement applies, specifically clarification if the
requirement applies to the following measuring devices:
•
•
•
•
•
•
Only equipment within the operations control room
Only equipment that provides values used to calculate AGC ACE
Only equipment that provides values to its SCADA system
Only equipment owned or operated by the BA
Only to new or replacement equipment
To all equipment that a BA owns or operates
BAL-005-0
Page 13 of 17
BAL-005-1 – Balancing Authority Control
R17. Each Balancing Authority shall at least annually check and calibrate its time error and
frequency devices against a common reference. The Balancing Authority shall adhere to the
minimum values for measuring devices as listed below:
Device
Accuracy
Digital frequency transducer
≤ 0.001 Hz
MW, MVAR, and voltage transducer
≤ 0.25% of full scale
Remote terminal unit
≤ 0.25% of full scale
Potential transformer
≤ 0.30% of full scale
Current transformer
≤ 0.50% of full scale
Existing Interpretation Approved by Board of Trustees May 2, 2007
BAL-005-0, Requirement 17 requires that the Balancing Authority check and calibrate its control
room time error and frequency devices against a common reference at least annually. The
requirement to “annually check and calibrate” does not address any devices outside of the
operations control room.
The table represents the design accuracy of the listed devices. There is no requirement within the
standard to “annually check and calibrate” the devices listed in the table, unless they are included
in the control center time error and frequency devices.
Interpretation provided by NERC Frequency Task Force on September 7, 2007 and Revised on November 16, 2007
As noted in the existing interpretation, BAL-005-0 Requirement 17 applies only to the time error and frequency devices that provide,
or in the case of back-up equipment may provide, input into the reporting or compliance ACE equation or provide real-time time error
or frequency information to the system operator. Frequency inputs from other sources that are for reference only are excluded. The
time error and frequency measurement devices may not necessarily be located in the system operations control room or owned by the
Balancing Authority; however the Balancing Authority has the responsibility for the accuracy of the frequency and time error
measurement devices. No other devices are included in R 17. The other devices listed in the table at the end of R17 are for reference
only and do not have any mandatory calibration or accuracy requirements.
New or replacement equipment that provides the same functions noted above requires the same calibrations. Some devices used for
time error and frequency measurement cannot be calibrated as such. In this case, these devices should be cross-checked against other
properly calibrated equipment and replaced if the devices do not meet the required level of accuracy.
Page 14 of 17
BAL-005-1 – Balancing Authority Control
Page 15 of 17
Standard BAL-005-0.2b — Automatic Generation ControlSupplemental Material
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon Board approval, the text from the
rationale boxes will be moved to this section.
Rationale for Requirement R1: Real-time operation of a Balancing Authority requires real-time
information. A sufficient scan rate is key to an Operator’s trust in real-time information.
Without a sufficient scan rate, an operator may question the accuracy of data during events,
which would degrade the operator’s ability to maintain reliability.
Rationale for Requirement R2: The RC is responsible for coordinating the reliability of bulk
electric systems for member BA’s. When a BA is unable to calculate its ACE for an extended
period of time, this information must be communicated to the RC within 15 minutes thereafter
so that the RC has sufficient knowledge of system conditions to assess any unintended
reliability consequences that may occur on the wide area.
Rationale for Requirement R3: Frequency is the basic measurement for interconnection health,
and a critical component for calculating Reporting ACE. Without sufficient available frequency
data the BA operator will lack situational awareness and will be unable to make correct
decisions when maintaining reliability.
Rationale for Requirement R4: System operators utilize Reporting ACE as a primary metric to
determine operating actions or instructions. When data inputs into the ACE calculation are
incorrect, the operator should be made aware through visual display. When an operator
questions the validity of data, actions are delayed and the probability of adverse events
occurring can increase.
Rationale for Requirement R5: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Since Reporting ACE is a measure of the
BA’s reliability performance for BAL-001, and BAL-002, it is critical that Reporting ACE be
sufficiently available to assure reliability.
Rationale for Requirement R6: Reporting ACE is a measure of the BA’s reliability performance
for BAL-001, and BAL-002. Without a process to address persistent errors in the ACE calculation,
the operator can lose trust in the validity of Reporting ACE resulting in delayed or incorrect
decisions regarding the reliability of the bulk electric system.
Rationale for Requirement R7: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Common source data is critical to
calculating Reporting ACE that is consistent between Balancing Authorities. When data sources
are not common, confusion can be created between BAs resulting in delayed or incorrect
operator action.
Page 16 of 17
Standard BAL-005-0.2b — Automatic Generation ControlSupplemental Material
The intent of Requirement R7 Part 7.1 is to provide accuracy in the measurement and
calculations used in Reporting ACE. It specifies the need for common metering points for
instantaneous values for the tie-line megawatt flow values between Balancing Authority Areas.
Common data source requirements also apply to instantaneous values for pseudo-ties and
dynamic schedules, and can extend to more than two Balancing Authorities that participate in
allocating shares of a generation resource in supplementary regulation, for example.
The intent of Requirement R7 Part 7.2 is to enable accuracy in the measurements and
calculations used in Reporting ACE. It specifies the need for common metering points for
hourly accumulated values for the time synchronized tie line MWh values agreed-upon
between Balancing Authority Areas. These time synchronized agreed-upon values are
necessary for use in the Operating Process required in R6 to identify and mitigate errors in the
scan-rate values used in Reporting ACE.
Page 17 of 17
Exhibit B
Proposed Reliability Standard FAC-001-3
FAC-001-3 Clean Version
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Page 1 of 9
FAC-001-3 — Facility Interconnection Requirements
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified generation Facilities are within a
Balancing Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
Page 2 of 9
FAC-001-3 — Facility Interconnection Requirements
The applicable Functional Entity shall keep data or evidence to show compliance
as identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Page 3 of 9
FAC-001-3 — Facility Interconnection Requirements
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning
Lower
N/A
Moderate VSL
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
OR
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
Severe VSL
The Transmission
Owner did not
document Facility
interconnection
requirements.
Page 4 of 9
FAC-001-3 — Facility Interconnection Requirements
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
R2
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 5 of 9
FAC-001-3 — Facility Interconnection Requirements
R3
Long-term
Planning
Lower
N/A
The Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
The Transmission
Owner failed to
address two parts of
Requirement R3 Part
3.1 through Part 3.3.
The Transmission
Owner failed to
address Requirement
R3 Part 3.1 through
Part 3.3.
R4
Long-term
Planning
Lower
N/A
The Generator Owner
failed to address one
part of Requirement
R4 Part 4.1 through
Part 4.3.
The Generator Owner
failed to address two
parts of Requirement
R4 Part 4.1 through
Part 4.3.
The Generator Owner
failed to address
Requirement R4 Part
4.1 through Part 4.3.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.
Page 6 of 9
FAC-001-3 — Facility Interconnection Requirements
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
3
February 11, 2016
Adopted by the Board of Trustees
Revision under
Project 2010-02
Moved BAL-0050.2b Requirement
R1 into FAC-0013 Requirements
R3 and R4
Page 7 of 9
Supplemental Material
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
•
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
•
Data required to properly study the interconnection
•
Voltage level and MW and MVAR capacity or demand at the point of interconnection
•
Breaker duty and surge protection
•
System protection and coordination
•
Metering and telecommunications
•
Grounding and safety issues
•
Insulation and insulation coordination
•
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
•
Power quality impacts
•
Equipment ratings
•
Synchronizing of Facilities
•
Maintenance coordination
•
Operational issues (abnormal frequency and voltages)
•
Inspection requirements for new or materially modified existing interconnections
•
Communications and procedures during normal and emergency operating conditions
Page 8 of 9
Supplemental Material
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon Board approval, the text from the
rationale boxes will be moved to this section.
Rationale for Requirement R3.3: Consistent with the Functional Model, there cannot be an
assumption that the entity owning the transmission will be the same entity providing the BA
function. It is the responsibility of the party interconnecting to make appropriate arrangements
with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries,
which also serves to facilitate the process of the coordination between the two entities that will
be required under numerous other standards upon the start of operation. Under 3.3, the
Transmission Owner is responsible for confirming that the party interconnecting has made
appropriate provisions with a Balancing Authority to operate within its metered boundaries.
Rationale for Requirement R4.3: Consistent with the Functional Model, there cannot be an
assumption that the entity owning the generation will be the same entity providing the BA
function. It is the responsibility of the party interconnecting to make appropriate arrangements
with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries,
which also serves to facilitate the process of the coordination between the two entities that will
be required under numerous other standards upon the start of operation. Under 4.3, the
Generator Owner is responsible for confirming that the party interconnecting has made
appropriate provisions with a Balancing Authority to operate within its metered boundaries.
Page 9 of 9
FAC-001-3 Redline Version
FAC-001-23 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-23
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.
Effective Date: The standard shall become effective on the first day of the first
calendar quarter that is one year after the date that this standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is one
year after the date this standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.Effective Date: See Implementation Plan
for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
Page 1 of 10
FAC-001-23 — Facility Interconnection Requirements
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified generation Facilities are within a
Balancing Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
Page 2 of 10
FAC-001-23 — Facility Interconnection Requirements
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Transmission Owner and applicable Generator OwnerFunctional Entity shall
keep data or evidence to show compliance as identified below unless directed by
its CEA to retain specific evidence for a longer period of time as part of an
investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Page 3 of 10
FAC-001-23 — Facility Interconnection Requirements
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long-term
Planning
Lower
N/A
Moderate VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
OR
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
High VSL
Severe VSL
The Transmission
Owner did not
document Facility
interconnection
requirements.
Page 4 of 10
FAC-001-23 — Facility Interconnection Requirements
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
R2
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 5 of 10
FAC-001-23 — Facility Interconnection Requirements
R3
Long-term
Planning
Lower
N/A
N/AThe Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
The Transmission
Owner addressed
eitherfailed to address
two parts of
Requirement R3, Part
3.1 orthrough Part 3.2
in its Facility
interconnection
requirements, but did
not address both.3.
The Transmission
Owner addressed
neitherfailed to address
Requirement R3, Part
3.1 northrough Part 3.2
in its Facility
interconnection
requirements. 3.
R4
Long-term
Planning
Lower
N/A
N/AThe Generator
Owner failed to
address one part of
Requirement R4 Part
4.1 through Part 4.3.
The applicable
Generator Owner
addressed eitherfailed
to address two parts of
Requirement R4, Part
4.1 orthrough Part 4.2
in its Facility
interconnection
requirements, but did
not address both.3.
The applicable
Generator Owner
addressed neitherfailed
to address
Requirement R4, Part
4.1 northrough Part 4.2
in its Facility
interconnection
requirements. 3.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.
Page 6 of 10
FAC-001-23 — Facility Interconnection Requirements
Version History
Version
0
Date
April 1, 2005
1
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
3
February 11, 2016
Adopted by the Board of Trustees
Change
Tracking
Effective Date
1
2
Action
Revision under
Project 2010-02
Moved BAL-0050.2b Requirement
R1 into FAC-0013 Requirements
R3 and R4
Page 7 of 10
Application Guidelines
Supplemental Material
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
Data required to properly study the interconnection
Voltage level and MW and MVAR capacity or demand at the point of interconnection
Breaker duty and surge protection
System protection and coordination
Metering and telecommunications
Grounding and safety issues
Insulation and insulation coordination
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
Power quality impacts
Equipment ratings
Synchronizing of Facilities
Maintenance coordination
Operational issues (abnormal frequency and voltages)
Inspection requirements for new or materially modified existing interconnections
Communications and procedures during normal and emergency operating conditions
Page 8 of 10
Application Guidelines
Supplemental Material
Page 9 of 10
Application Guidelines
Supplemental Material
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon Board approval, the text from the
rationale boxes will be moved to this section.
Rationale for Requirement R3.3: Consistent with the Functional Model, there cannot be an
assumption that the entity owning the transmission will be the same entity providing the BA
function. It is the responsibility of the party interconnecting to make appropriate arrangements
with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries,
which also serves to facilitate the process of the coordination between the two entities that will
be required under numerous other standards upon the start of operation. Under 3.3, the
Transmission Owner is responsible for confirming that the party interconnecting has made
appropriate provisions with a Balancing Authority to operate within its metered boundaries.
Rationale for Requirement R4.3: Consistent with the Functional Model, there cannot be an
assumption that the entity owning the generation will be the same entity providing the BA
function. It is the responsibility of the party interconnecting to make appropriate arrangements
with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries,
which also serves to facilitate the process of the coordination between the two entities that will
be required under numerous other standards upon the start of operation. Under 4.3, the
Generator Owner is responsible for confirming that the party interconnecting has made
appropriate provisions with a Balancing Authority to operate within its metered boundaries.
Page 10 of 10
Exhibit C
Redline of Reliability Standard BAL-006-2
Standard BAL-006-2 — Inadvertent Interchange
Introduction
1.
Title:
Inadvertent Interchange
2.
Number:
BAL-006-2
3.
Purpose:
This standard defines a process for monitoring Balancing Authorities to ensure that, over the
long term, Balancing Authority Areas do not excessively depend on other Balancing Authority
Areas in the Interconnection for meeting their demand or Interchange obligations.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
Requirements
R1. Each Balancing Authority shall calculate and record hourly Inadvertent Interchange.
(Violation Risk Factor: Lower)
R2. Each Balancing Authority shall include all AC tie lines that connect to its Adjacent Balancing
Authority Areas in its Inadvertent Interchange account. The Balancing Authority shall take
into account interchange served by jointly owned generators. (Violation Risk Factor: Lower)
R3. Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection
points are equipped with common megawatt-hour meters, with readings provided hourly to the
control centers of Adjacent Balancing Authorities. (Violation Risk Factor: Lower)
R4. Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and
Actual Net Interchange value and shall record these hourly quantities, with like values but
opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange based on
the following: (Violation Risk Factor: Lower)
R4.1. Each Balancing Authority, by the end of the next business day, shall agree with its
Adjacent Balancing Authorities to: (Violation Risk Factor: Lower)
The hourly values of Net Interchange Schedule. (Violation Risk Factor: Lower)
The hourly integrated megawatt-hour values of Net Actual Interchange. (Violation Risk
Factor: Lower)
R4.2. Each Balancing Authority shall use the agreed-to daily and monthly accounting data to
compile its monthly accumulated Inadvertent Interchange for the On-Peak and OffPeak hours of the month. (Violation Risk Factor: Lower)
R4.3. A Balancing Authority shall make after-the-fact corrections to the agreed-to daily and
monthly accounting data only as needed to reflect actual operating conditions (e.g. a
meter being used for control was sending bad data). Changes or corrections based on
non-reliability considerations shall not be reflected in the Balancing Authority’s
Inadvertent Interchange. After-the-fact corrections to scheduled or actual values will
not be accepted without agreement of the Adjacent Balancing Authority(ies).
(Violation Risk Factor: Lower)
R5. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual
Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following
month shall, for the purposes of dispute resolution, submit a report to their respective Regional
Reliability Organization Survey Contact. The report shall describe the nature and the cause of
the dispute as well as a process for correcting the discrepancy. (Violation Risk Factor: Lower)
Standard BAL-006-2
1
Standard BAL-006-2 — Inadvertent Interchange
C.
Measures
None specified.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.
These summaries shall not include any after-the-fact changes that were not agreed to
by the Source Balancing Authority, Sink Balancing Authority and all Intermediate
Balancing Authority(ies).
1.2.
Inadvertent Interchange summaries shall include at least the previous accumulation, net
accumulation for the month, and final net accumulation, for both the On-Peak and OffPeak periods.
1.3.
Each Balancing Authority shall submit its monthly summary report to its Regional
Reliability Organization Survey Contact by the 15th calendar day of the following
month.
1.4.
Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as
requested by the NERC Operating Committee to determine the Balancing Authority’s
Interchange error(s) due to equipment failures or improper scheduling operations, or
improper AGC performance.
1.5.
Each Regional Reliability Organization shall prepare a monthly Inadvertent
Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent
Interchange and all-time accumulated Inadvertent Interchange. Each Regional
Reliability Organization shall submit a monthly accounting to NERC by the 22nd day
following the end of the month being summarized.
Standard BAL-006-2
2
Standard BAL-006-2 — Inadvertent Interchange
2.
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
N/A
N/A
N/A
Each Balancing Authority failed to
calculate and record hourly
Inadvertent Interchange.
R2.
N/A
N/A
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
OR
AND
Failed to take into account
interchange served by jointly
owned generators.
Failed to take into account
interchange served by jointly
owned generators.
R3.
N/A
N/A
N/A
The Balancing Authority failed to
ensure all of its Balancing
Authority Area interconnection
points are equipped with common
megawatt-hour meters, with
readings provided hourly to the
control centers of Adjacent
Balancing Authorities.
R4.
The Balancing Authority failed to
record Actual Net Interchange
values that are equal but opposite
in sign to its Adjacent Balancing
Authorities.
The Balancing Authority failed to
compute Inadvertent Interchange.
The Balancing Authority failed to
operate to a common Net
Interchange Schedule that is equal
but opposite to its Adjacent
Balancing Authorities.
N/A
R4.1.
N/A
N/A
N/A
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Standard BAL-006-2
3
Standard BAL-006-2 — Inadvertent Interchange
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
Schedule.
AND
The hourly integrated megawatthour values of Net Actual
Interchange.
R4.1.1.
N/A
N/A
N/A
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
R4.1.2.
N/A
N/A
N/A
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
integrated megawatt-hour values of
Net Actual Interchange.
R4.2.
N/A
N/A
N/A
The Balancing Authority failed to
use the agreed-to daily and
monthly accounting data to
compile its monthly accumulated
Inadvertent Interchange for the OnPeak and Off-Peak hours of the
month.
R4.3.
N/A
N/A
N/A
The Balancing Authority failed to
make after-the-fact corrections to
the agreed-to daily and monthly
accounting data to reflect actual
operating conditions or changes or
corrections based on non-reliability
considerations were reflected in the
Balancing Authority’s Inadvertent
Standard BAL-006-2
4
Standard BAL-006-2 — Inadvertent Interchange
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
Interchange.
R5.
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities, submitted a
report to their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute but failed
to provide a process for correcting
the discrepancy.
Standard BAL-006-2
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities by the 15th
calendar day of the following
month, failed to submit a report to
their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute as well as a
process for correcting the
discrepancy.
N/A
N/A
5
Standard BAL-006-2 — Inadvertent Interchange
E.
Regional Differences
1.
Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March
25, 2004includes SPP effective May 1, 2006.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
April 6, 2006
Added following to “Effective Date:” This
standard will expire for one year beyond the
effective date or when replaced by a new version
of BAL-006, whichever comes first.
Errata
2
November 5, 2009
Added approved VRFs and VSLs to document.
Revision
Removed MISO from list of entities with an
Inadvertent Interchange Accounting Waiver
(Project 2009-18).
2
November 5, 2009
Approved by the Board of Trustees
2
January 6, 2011
Approved by FERC
Standard BAL-006-2
6
Exhibit D
Implementation Plan for Proposed BAL-005-1
Implementation Plan
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Reliability Standard BAL-005-1
R equested Approval
•
BAL-005-1 – Balancing Authority Controls
Requested Retirement
•
BAL-005-0.2b – Automatic Generation Control
•
BAL-006-2 – Inadvertent Interchange - Requirement R3
Prerequisite Approval
•
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (F A ): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NI A ): The algebraic sum of actual megawatt transfers
across all Tie Lines, including Pseudo‐Ties, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NI S ): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (I ME ): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (I ATEC ): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
I𝑨𝑨𝑨𝑨𝑨𝑨𝑨𝑨 =
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐 𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
(𝟏𝟏−𝒀𝒀)∗𝑯𝑯
when operating in Automatic Time Error Correction Mode.
The absolute value of I ATEC shall not exceed L max .
I ATEC shall be zero when operating in any other AGC mode.
• L max is the maximum value allowed for I ATEC set by each BA between 0.2*|B i | and
L 10 , 0.2*|B i |≤ L max ≤ L 10 .
•
•
•
•
•
•
•
•
•
•
•
•
L 10 = 1.65 ∗ ε10 �(−10Bi )(−10BS ) .
ε10 is a constant derived from the targeted frequency bound. It is the targeted rootmean-square (RMS) value of ten-minute average frequency error based on
frequency performance over a given year. The bound, ε 10 , is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
B i = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
B S = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PII hourly ) is (1-Y) * (II actual - B i * ΔTE/6)
II actual is the hourly Inadvertent Interchange for the last hour.
ΔTE is the hourly change in system Time Error as distributed by the Interconnection
time monitor,where: ΔTE = TE end hour – TE begin hour – TD adj – (t)*(TE offset )
TD adj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TE offset is 0.000 or +0.020 or -0.020.
PII accum is the Balancing Authority Area’s accumulated PII hourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
BAL-005-1 – Balancing Authority Control
2
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
𝒐𝒐𝒐𝒐⁄𝒐𝒐𝒐𝒐𝒐𝒐𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑
= 𝒍𝒍𝒍𝒍𝒍𝒍𝒍𝒍 𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒑𝒅𝒅′ 𝒔𝒔 PII𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂
+ PII𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉𝒉
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NI A − NI S ) − 10B (F A − F S ) – I ME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NI A − NI S ) − 10B (F A − F S ) – I ME + I ATEC
Where:
• NI A
=
Actual Net Interchange.
•
NI S
=
Scheduled Net Interchange.
•
B
=
Frequency Bias Setting.
•
FA
=
Actual Frequency.
•
FS
=
Scheduled Frequency.
•
I ME
=
Interchange Meter Error.
•
I ATEC
=
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie-line Bias (TLB)
Control and require the use of an ACE equation similar to the Reporting ACE
defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAAs on an Interconnection and is(are) consistent with
the following four principles of Tie Line Bias control will provide a valid alternative
to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency F S for all BAAs at all times; and,
BAL-005-1 – Balancing Authority Control
3
4. Excludes metering or computational errors. (The inclusion and use of the I ME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC): A process designed and used to adjust a
Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in
that of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
Pseudo-Tie: A time-varying energy transfer that is updated in Real-time and included in the
Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected Balancing
Authorities’ Reporting ACE equation (or alternate control processes).
Balancing Authority: The responsible entity that integrates resource plans ahead of time,
maintains Demand and resource balance within a Balancing Authority Area, and supports
Interconnection frequency in real time.
Applicable Entities
•
Balancing Authority
Applicable Facilities
•
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
BAL-005-1 – Balancing Authority Control
4
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented immediately after BAL-005-1 becomes effective as
reflected in the Implementation Plan for FAC-001-3, and BAL-006-2 Requirement R3 will be
retired concurrently with the effective date for BAL-005-1 . Finally, to ensure proper
coordination with BAL-001-2, approved by the Commission in Order No. 810 issued on April
16, 2015, the following definitions associated with BAL-005-1 will be implemented concurrently
with the effective date for BAL-001-2:
•
Reporting ACE
•
Actual Frequency
•
Actual Net Interchange
•
Scheduled Net Interchange
•
Interchange Meter Error
•
Automatic Time Error Correction
Effective Dates
Definitions
The definitions of the following terms shall become effective immediately after the
effective date of BAL-001-2 1:
•
Reporting ACE
•
Actual Frequency
•
Actual Net Interchange
•
Scheduled Net Interchange
•
Interchange Meter Error
•
Automatic Time Error Correction
BAL-005-1
Where approval by an applicable governmental authority is required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
Because the definition of “Reporting ACE” associated with BAL-005-1 will become effective immediately after the
effective date of BAL-001-2, the definition of “Reporting ACE” that was approved by the Commission on April 16,
2015 in Order No. 810 (151 FERC ¶ 61,048) will never go into effect.
1
BAL-005-1 – Balancing Authority Control
5
after the effective date of the applicable governmental authorities order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
after the date the standard is adopted by the NERC Board of Trustees’, or as otherwise
provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Automatic Generation Control, Pseudo Tie and Balancing Authority
shall be retired at midnight of the day immediately prior to the effective date of BAL-005-1, in
the jurisdiction in which the new standard is becoming effective.
The existing definitions of Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Meter Error, and Automatic Time Error Correction
shall be retired immediately after the effective date of BAL-001-2. 2
Note that the definition of Reporting ACE that was approved by the Commission in Order No. 810, which will
replace the existing definition of Reporting ACE, will be retired immediately prior to the effective date for the
revised definition of Reporting ACE, as described above. As such, the definition of Reporting ACE approved by the
Commission in Order No. 810 will never go into effect.
2
BAL-005-1 – Balancing Authority Control
6
Exhibit E
Implementation Plan for FAC-001-3
Implementation Plan
Reliability Standard FAC-001-3
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
FAC-001-3 – Facility Interconnection Requirements
Requested Retirement
FAC-001-2 – Facility Interconnection Requirements
Prerequisite Approval
BAL-005-1 – Balancing Authority Controls
Revisions to Glossary Terms
None
Applicable Entities
Balancing Authority
Background
Reliability Standard FAC-001-3 addresses Facility Interconnection Requirements, which ensure
the avoidance of adverse impacts on the reliability of the Bulk Electric System by requiring
Transmission Owners and applicable Generator Owners to document and make Facility
interconnection requirements available so that entities seeking to interconnect will have
necessary information. Reliability Standard FAC-001-3 and associated Implementation Plan was
developed in conjunction with BAL-005-1 (Balancing Authority Controls) to ensure that entities
with facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented concurrently with BAL-005-1, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
FAC-001-3 shall become effective on the effective date of BAL-005-1.
Retirements
FAC-001-2 (Facility Interconnection Requirements) shall be retired immediately prior to the
Effective Date of FAC-001-3 (Facility Interconnection Requirements) in the particular
jurisdiction in which the revised standard is becoming effective.
FAC‐001‐3 – Facility Interconnection Requirements
2
Exhibit F
Implementation Plan for Retirement of BAL-006-2
Implementation Plan
Reliability Standard BAL-006-2
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
N/A
Requested Retirement
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
BAL-005-1 – Balancing Authority Controls
Prerequisite Events
NERC Operating Committee approval of Inadvertent Interchange Guideline1
Revisions to Glossary Terms
None
Applicable Entities
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-2 will be retired concurrently with the effective date of BAL-005-1 and requisite
approval of Inadvertent Interchange Guideline, as reflected in the “Prerequisite Approvals” and
“Prerequisite Events” sections above.
Effective Dates
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.
1
BAL-006-2 shall be retired on the effective date of BAL-005-1 and the approval of Inadvertent
Interchange Guideline.
FAC‐001‐3 – Facility Interconnection Requirements
2
Exhibit G
Analysis of Violation Risk Factors and Violation Severity Levels for BAL-005-1
Violation Risk Factor and Violation Severity
Level Assignments
Project 2010-14.2.1 Balancing Authority Reliability-based
Controls
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs)
and violation severity levels (VSLs) for each requirement in BAL‐005‐1, Balancing Authority Control.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the
determination of an initial value range for the base penalty amount regarding violations of
requirements in FERC‐approved reliability standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard drafting team applied the following NERC criteria when proposing
VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to Bulk Electric System instability, separation, or a cascading
sequence of failures, or could place the Bulk Electric System at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System. However,
violation of a medium‐risk requirement is unlikely to lead to Bulk Electric System instability, separation,
or cascading failures; or a requirement in a planning time frame that, if violated, could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium‐risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations to lead
to Bulk Electric System instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
BAL‐005‐1
VRF and VSL Assignments
1
Lower Risk Requirement
A requirement that is administrative in nature, and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the Bulk Electric System, or the ability to
effectively monitor and control the Bulk Electric System; or a requirement that is administrative in
nature and a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the Bulk Electric System, or the ability to effectively monitor, control, or
restore the Bulk Electric System. A planning requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The commission seeks to ensure that Violation Risk Factors assigned to requirements of reliability
standards in these identified areas appropriately reflect their historical critical impact on the reliability
of the Bulk Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk Power System:2
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The commission expects a rational connection between the sub‐requirement Violation Risk Factor
assignments and the main requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
BAL‐005‐1
VRF and VSL Assignments
2
The commission expects the assignment of Violation Risk Factors corresponding to requirements that
address similar reliability goals in different reliability standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single requirement co‐mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such requirement must not be watered down to reflect the lower risk
level associated with the less important objective of the reliability standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4.
Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s reliability
standards and implies that these requirements should be assigned a “High” VRF, Guideline 4 directs
assignment of VRFs based on the impact of a specific requirement to the reliability of the system. The
SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance; and, therefore,
concentrated its approach on the reliability impact of the requirements.
VRF for BAL-005-1:
There are seven requirements in BAL‐005‐1. All of the requirements were assigned a “Medium” VRF.
VRF for BAL-005-1, Requirement R1:
•
FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain sub‐requirements. All of the requirements in BAL‐005‐1 are assigned a “Medium” VRF.
Requirement R1 is similar in scope to Requirement R3 and Requirement R5. This is also
consistent with the current FERC approved VRF for BAL‐005‐0.2b Requirement R8.
•
FERC Guideline 3 — Consistency among reliability standards exists. This requirement is
identical to the current enforceable BAL‐005‐0.2b Standard Requirement R8 which has an
approved Medium VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
BAL‐005‐1
VRF and VSL Assignments
3
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for BAL-005-1, Requirement R2:
•
FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain sub‐requirements. All of the requirements in BAL‐005‐1 are assigned a “Medium” VRF.
This is also consistent with the current FERC approved VRF for BAL‐005‐0.2b Requirement R6.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is
identical to the current enforceable BAL‐005‐0.2b standard Requirement R6 which has an
approved Medium VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for BAL-005-1, Requirement R3:
•
FERC Guideline 2 — Consistency within a reliability standard exists. All of the requirements in
BAL‐005‐1 are assigned a “Medium” VRF. This is also consistent with the current FERC
approved VRF in BAL‐005‐0.2b Requirement R8.1.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL‐005‐0.2b standard Requirement R8.1 which has an
approved Medium VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
BAL‐005‐1
VRF and VSL Assignments
4
VRF for BAL-005-1, Requirement R4:
•
FERC Guideline 2 — Consistency within a reliability standard exists. This requirement does not
contain sub‐requirements. All of the requirements in BAL‐005‐1 are assigned a “Medium” VRF.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL‐005‐0.2b standard Requirement R8.1 which has an
approved Medium VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for BAL-005-1, Requirement R5:
•
FERC Guideline 2 — Consistency within a reliability standard exists. This requirement does not
contain sub‐requirements. All of the requirements in BAL‐005‐1 are assigned a “Medium” VRF.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to BAL‐005‐0.2b standard Requirement R3 which has a Medium VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for BAL-005-1, Requirement R6:
•
FERC Guideline 2 — Consistency within a reliability standard exists. This requirement does not
contain sub‐requirements. All of the requirements in BAL‐005‐1 are assigned a “Medium” VRF.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to BAL‐005‐0.2b standard Requirement R7 which has a Medium VRF.
BAL‐005‐1
VRF and VSL Assignments
5
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for BAL-005-1, Requirement R7:
•
FERC Guideline 2 — Consistency within a reliability standard exists. All of the requirements in
BAL‐005‐1 are assigned a “Medium” VRF. This is also consistent with the current FERC
approved VRF in BAL‐005‐0.2b Requirement R12 which has an approved Medium VRF and BAL‐
006‐2 Requirement R3 which has a Lower VRF. However, the SDT felt that this requirement
was not purely an administrative requirement and therefore deserved a higher VRF.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL‐005‐0.2b Requirement R12 which has an approved
Medium VRF and BAL‐006‐2 Requirement R3 which has an approved Lower VRF. However, the
SDT felt that this requirement was not purely an administrative requirement and therefore
deserved a higher VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
BAL‐005‐1
VRF and VSL Assignments
6
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence that would
be reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may find
during a typical audit. The SDT based its assignment of VSLs on the following NERC criteria:
Lower
Moderate
Missing a minor
Missing at least one
element (or a small
significant element (or
percentage) of the
a moderate
required performance. percentage) of the
required performance.
The performance or
product measured has The performance or
significant value, as it product measured still
almost meets the full has significant value in
intent of the
meeting the intent of
requirement.
the requirement.
High
Severe
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance,
or is missing a single
vital component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance
measured does not
meet the intent of the
requirement, or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC’s VSL Guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement in BAL‐005‐1 meet the FERC Guidelines for assessing VSLs:
BAL‐005‐1
VRF and VSL Assignments
7
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of noncompliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of noncompliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of noncompliance with a requirement is a
separate violation. Section 4 of the Sanction Guidelines states that assessing penalties on a per‐
violation‐per‐day basis is the “default” for penalty calculations.
BAL‐005‐1
VRF and VSL Assignments
8
VSLs for BAL-005-1 Requirement R1:
Compliance with
NERC VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on a single
violation and not a
cumulative violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R1
The NERC VSL
Guidelines are
satisfied. The
requirement is
binary and the
performance
measured does
not meet the
intent of the
requirement.
BAL‐005‐1
VRF and VSL Assignments
As drafted, the
proposed VSLs do not
lower the current level
of compliance.
Proposed VSL is binary and
therefore only has a severe VSL.
The proposed VSL language does
not include ambiguous terms.
The VSL is similar to the current
approved VSL for BAL‐005‐0.2b
Requirement R8.
9
VSLs for BAL-005-1 Requirement R2:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
the amount of time an
entity is non‐compliant
with the requirement.
Proposed VSLs are
consistent with the
requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R2.
The NERC VSL The proposed VSLs do not
Guidelines are lower the current level of
satisfied by
compliance.
incorporating
levels of
noncompliance
performance.
BAL‐005‐1
VRF and VSL Assignments
Proposed VSLs are not
binary. Proposed VSL
language does not include
ambiguous terms and
ensures uniformity and
consistency in the
determination of penalties.
10
VSLs for BAL-005-1 Requirement R3:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R3.
The NERC VSL As drafted, the proposed
Guidelines are VSLs do not lower the
satisfied by
current level of compliance.
incorporating
levels of
noncompliance
performance.
BAL‐005‐1
VRF and VSL Assignments
Proposed VSLs are not
binary. Proposed VSL
language does not include
ambiguous terms and
ensures uniformity and
consistency in the
determination of penalties
based only on the amount of
time an entity is non‐
compliant with the
requirement.
11
VSLs for BAL-005-1 Requirement R4:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R4.
The NERC VSL As drafted, the proposed
Guidelines are VSLs do not lower the
satisfied. The current level of compliance.
requirement is
binary and the
performance
measured does
not meet the
intent of the
requirement.
BAL‐005‐1
VRF and VSL Assignments
Proposed VSL is binary and
therefore only has a severe
VSL. Proposed VSL language
does not include ambiguous
terms and ensures
uniformity and consistency
in the determination of
penalties based only on
whether the information
was provided.
12
VSLs for BAL-005-1 Requirement R5:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R5.
The NERC VSL As drafted, the proposed
Guidelines are VSLs do not lower the
satisfied by
current level of compliance.
incorporating
levels of
noncompliance
performance.
BAL‐005‐1
VRF and VSL Assignments
Proposed VSLs are not
binary. Proposed VSL
language does not include
ambiguous terms and
ensures uniformity and
consistency in the
determination of penalties
based only on the amount of
time an entity is non‐
compliant with the
requirement.
13
VSLs for BAL-005-1 Requirement R6:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R6.
The NERC VSL
Guidelines are
satisfied. The
requirement is
binary and the
performance
measured does
not meet the
intent of the
requirement.
BAL‐005‐1
VRF and VSL Assignments
This requirement is new. As
drafted, the proposed VSL
does not lower the current
level of compliance.
Proposed VSL is binary and
therefore only has a severe
VSL. Proposed VSL language
does not include ambiguous
terms and ensures
uniformity and consistency
in the determination of
penalties based only on
whether the entity
implemented an Operating
Process to identify and
mitigate errors.
14
VSLs for BAL-005-1 Requirement R7:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R7.
The NERC VSL As drafted, the proposed
Guidelines are VSL does not lower the
satisfied. The current level of compliance.
requirement is
binary and the
performance
measured does
not meet the
intent of the
requirement.
BAL‐005‐1
VRF and VSL Assignments
Proposed VSL is binary and
therefore only has a severe
VSL. Proposed VSL language
does not include ambiguous
terms and ensures
uniformity and consistency
in the determination of
penalties.
15
Exhibit H
Analysis of Violation Risk Factors and Violation Severity Levels for FAC-001-3
Violation Risk Factor and Violation Severity
Level Assignments
Project 2010-14.2.1 Balancing Authority Reliability-based
Controls
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs)
and violation severity levels (VSLs) for each requirement in FAC‐001‐3, Facility Interconnection
Requirements. Each primary requirement is assigned a VRF and a set of one or more VSLs. These
elements support the determination of an initial value range for the base penalty amount regarding
violations of requirements in FERC‐approved reliability standards, as defined in the ERO Sanction
Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard drafting team applied the following NERC criteria when proposing
VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or a requirement in a planning time
frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to Bulk Electric System instability, separation, or a cascading
sequence of failures, or could place the Bulk Electric System at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System. However,
violation of a medium‐risk requirement is unlikely to lead to Bulk Electric System instability, separation,
or cascading failures; or a requirement in a planning time frame that, if violated, could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium‐risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations to lead
FAC‐001‐3
VRF and VSL Assignments
1
to Bulk Electric System instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that is administrative in nature, and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the Bulk Electric System, or the ability to
effectively monitor and control the Bulk Electric System; or a requirement that is administrative in
nature and a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the Bulk Electric System, or the ability to effectively monitor, control, or
restore the Bulk Electric System. A planning requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting VRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The commission seeks to ensure that Violation Risk Factors assigned to requirements of reliability
standards in these identified areas appropriately reflect their historical critical impact on the reliability
of the Bulk Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk Power System:2
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
FAC‐001‐3
VRF and VSL Assignments
2
The commission expects a rational connection between the sub‐requirement Violation Risk Factor
assignments and the main requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The commission expects the assignment of Violation Risk Factors corresponding to requirements that
address similar reliability goals in different reliability standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single requirement co‐mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such requirement must not be watered down to reflect the lower risk
level associated with the less important objective of the reliability standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4.
Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s reliability
standards and implies that these requirements should be assigned a “High” VRF, Guideline 4 directs
assignment of VRFs based on the impact of a specific requirement to the reliability of the system. The
SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance; and, therefore,
concentrated its approach on the reliability impact of the requirements.
VRF for FAC-001-3:
There are four requirements in FAC‐001‐3. All of the requirements were assigned a “Lower” VRF.
VRF for FAC-001-3, Requirement R1:
There were no changes made to requirement R1. The current FERC approved VRFs are proposed to
remain in effect.
VRF for FAC-001-3, Requirement R2:
There were no changes made to requirement R2. The current FERC approved VRFs are proposed to
remain in effect.
VRF for FAC-001-3, Requirement R3:
FAC‐001‐3
VRF and VSL Assignments
3
•
FERC Guideline 2 — Consistency within a reliability standard exists. All of the requirements in
FAC‐001‐3 are assigned a “Lower” VRF. This is also consistent with the current FERC approved
VRF in FAC‐001‐2 Requirement R3.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable FAC‐001‐2 standard Requirement R3 which has an
approved Lower VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
VRF for FAC-001-3, Requirement R4:
•
FERC Guideline 2 — Consistency within a reliability standard exists. All of the requirements in
FAC‐001‐3 are assigned a “Lower” VRF. This is also consistent with the current FERC approved
VRF in FAC‐001‐2 Requirement R4.
•
FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable FAC‐001‐2 standard Requirement R4 which has an
approved Lower VRF.
•
FERC Guideline 4 — Consistency with NERC’s Definition of the VRF level selected exists. This
requirement, if violated, could directly affect the electrical state or the capability of the Bulk
Electric System, or the ability to effectively monitor and control the Bulk Electric System, but
violation, in itself, would unlikely result in the Bulk Electric System instability, separation, or
cascading failures since this requirement is an after‐the‐fact calculation, not performed in Real‐
time.
•
FERC Guideline 5 — This requirement does not co‐mingle reliability objectives.
FAC‐001‐3
VRF and VSL Assignments
4
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence that would
be reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may find
during a typical audit. The SDT based its assignment of VSLs on the following NERC criteria:
Lower
Moderate
Missing a minor
Missing at least one
element (or a small
significant element (or
percentage) of the
a moderate
required performance. percentage) of the
required performance.
The performance or
product measured has The performance or
significant value, as it product measured still
almost meets the full has significant value in
intent of the
meeting the intent of
requirement.
the requirement.
High
Severe
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance,
or is missing a single
vital component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance
measured does not
meet the intent of the
requirement, or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC’s VSL Guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement in FAC‐001‐3 meet the FERC Guidelines for assessing VSLs:
FAC‐001‐3
VRF and VSL Assignments
5
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of noncompliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of noncompliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of noncompliance with a requirement is a
separate violation. Section 4 of the Sanction Guidelines states that assessing penalties on a per‐
violation‐per‐day basis is the “default” for penalty calculations.
FAC‐001‐3
VRF and VSL Assignments
6
VSLs for FAC-001-3 Requirement R1:
There were no changes made to requirement R1. The current FERC approved VSLs are proposed to remain in effect.
VSLs for FAC-001-3 Requirement R2:
There were no changes made to requirement R2. The current FERC approved VRFs are proposed to remain in effect.
FAC‐001‐3
VRF and VSL Assignments
7
VSLs for FAC-001-3 Requirement R3:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R3.
The NERC VSL
Guidelines are
satisfied by
incorporating
levels of
noncompliance
performance.
FAC‐001‐3
VRF and VSL Assignments
As drafted, the proposed
VSLs do not lower the
current level of compliance.
The proposed VSLs are
similar to the current FERC
approved VSLs in FAC‐001‐2
Requirement R3.
Proposed VSLs are not
binary. Proposed VSL
language does not include
ambiguous terms and
ensures uniformity and
consistency in the
determination of penalties
based only on the number of
parts the entity failed to
address.
8
VSLs for FAC-001-3 Requirement R4:
Compliance with
NERC VSL
Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Proposed VSLs do not
expand on what is
required in the
requirement. Proposed
VSLs are consistent with
the requirement.
Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R4.
The NERC VSL
Guidelines are
satisfied by
incorporating
levels of
noncompliance
performance.
FAC‐001‐3
VRF and VSL Assignments
As drafted, the proposed
VSLs do not lower the
current level of compliance.
The proposed VSLs are
similar to the current FERC
approved VSLs in FAC‐001‐2
Requirement R3.
Proposed VSL is binary and
therefore only has a severe
VSL. Proposed VSL language
does not include ambiguous
terms and ensures
uniformity and consistency
in the determination of
penalties based only on the
number of parts the entity
failed to address.
9
Exhibit I
BAL-005-1 Mapping Document
Project 2010-14.2.1 Mapping Document
Transition of BAL-005-0.2b to BAL-005-1
Requirement in
Approved Standard
BAL‐005‐1 R1
BAL‐005‐0.2b R2
BAL‐005‐0.2b R3
BAL‐005‐0.2b R4
BAL‐005‐0.2b R5
Standard: BAL‐005‐1 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
Requirements R1 Parts R1.1 and R1.2 do not provide for necessary
Requirement R1 Part R1.1 and Part R1.2
information concerning the calculation of Reporting ACE. The
have been moved into FAC‐001‐2
requirement provides for information necessary when connecting to
Requirement R3 and R4. Requirement R1
the electric system.
Part R1.3 is being retired.
Requirement R1 Part 1.3 is being retired in conjunction with the Risk‐
based Registration initiative de‐certifying the LSE function.
This requirement was retired as part of the original Paragraph 81
Retired
project. Its retirement was approved by FERC effective January 21,
2014.
This requirement can be retired since coordination of common values
Retire
between Adjacent BAs is covered in the Requirement R7.
This requirement can be retired since coordination of common values
Retire
between Adjacent BAs is covered in the Requirement R7.
This requirement can be retired since coordination of common values
Retire
between Adjacent BAs is covered in the Requirement R7.
Requirement in
Approved Standard
BAL‐005‐0.2b R6
BAL‐005‐0.2b R7
BAL‐005‐0.2b R8
BAL‐005‐0.2b R9
Standard: BAL‐005‐1 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The portion of the requirement concerning calculating ACE was moved
Moved to definition of Reporting ACE and
into the definition for Reporting ACE. The portion of the requirement
Requirement R2
concerning an entity’s inability to calculate Ace for more than 30
minutes was moved into Requirement R2.
This requirement should be retired under Paragraph 81 criteria. The
first sentence covers having a functional EMS or other system capable
of calculating Reporting ACE and controlling resources, though
Retire
resources can be dispatched manually without any detriment to
reliability. The SDT believes that the term “operate AGC” in R7 refers to
the capability to continuously calculate ACE, not automatic control of
resources to the extent BAs cannot take resources off “AGC” mode.
The body of this requirement was moved to
The body of this requirement has been moved to Requirement R1 and
Requirement R1 and Part 8.1 was moved
Part 8.1 has been moved into Requirement R3.
into Requirement R3
R9 is covered in the definition of Reporting ACE, and the proposed R7
ensures that the BA does not include any Interchange in its Reporting
ACE that does not have an Adjacent BA.
Regarding R9.1, the Actual Net Interchange and Scheduled Net
Interchange values in the Reporting ACE calculation include provisions
Retire
for the Balancing Authority to include its high voltage direct (HVDC) link
to another asynchronous interconnection. By assuring the values are
handled consistently in the actual and scheduled Interchange terms
included in the real‐time Reporting ACE by definition, the Balancing
Authority is not being instructed “how” to implement the HVDC link,
but allowed to decide the method it will use.
2
Requirement in
Approved Standard
BAL‐005‐0.2b R10
BAL‐005‐0.2b R11
BAL‐005‐0.2b R12
BAL‐005‐0.2b R13
BAL‐005‐0.2b R14
BAL‐005‐0.2b R15
BAL‐005‐0.2b R16
Standard: BAL‐005‐1 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The basics of this requirement is factored into the definition of
Retire
Scheduled Net Interchange (NIS) used in the Reporting ACE calculation
as defined in the NERC Glossary.
The basics of this requirement is factored into the definition of
Retire
Scheduled Net Interchange (NIS) used in the Reporting ACE calculation
as defined in the NERC Glossary.
Moved to Requirement R7
This requirement has been moved to Requirement R7.
The portion of the requirement concerning common time
synchronization was moved into Requirement R7. The portion of the
Moved to Requirement R7
requirement concerning an equipment error was moved into
Requirement R7.
Moved to Requirement R4 and Requirement This requirement has been moved into Requirement R4 and
R7
Requirement R7.
This requirement is duplicative of the intent of EOP‐008 ‐ Loss
of Control Room Functionality. In addition, proposed R3
Retired
requires a performance level that the Balancing Authority
Area must meet. The standard does not tell the BAA how to
meet it.
Moved to Requirement R4
This requirement has been moved into Requirement R4.
3
Requirement in
Approved Standard
BAL‐005‐0.2b R17
Standard: BAL‐005‐1 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This requirement which address accuracy of RTU and transducers is
meaningless in today’s world. RTUs do not quantize measurement
anymore, these are done by relay or meters. Transducers are not used
anymore and have been replaced by meters and relays which measure
quantities. This requirement should be restored such that it actually
supports an accurate calculation of ACE and proper operation of AGC
Partially retired (partially captured in new
by specifying accuracy requirements for all telemetry associated with
Requirement R3)
ACE (Frequency, MW and the associated sensing devices and
telemetry). In addition, the interpretation effective 8/27/2008 in BAL‐
005‐0.2.b for R17 states that this requirement is specific to the
equipment used to determine the frequency component required for
reporting ACE. This is now being captured in Requirement R3.
4
Exhibit J
FAC-001-3 Mappnig Document
Project 2010-14.2.1 Mapping Document
Transition of FAC-001-2 to FAC-001-3
Requirement in
Approved Standard
FAC‐001‐2 R1
FAC‐001‐2 R2
FAC‐001‐2 R3
FAC‐001‐2 R4
BAL‐005‐0.2b R1
BAL‐005‐0.2b R1
Standard: FAC‐001‐3 – Facility Interconnection Requirements
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
No change
No change
No change
No change
No change
No change
No change
No change
This requirement was moved from BAL‐005‐0.2b since it does not
Moved from BAL‐005‐0.2b Requirement R1 provide for information regarding the calculation of Reporting ACE.
to FAC‐001‐3 R3 Part 3.3
The requirement is more in line with facilities attaching to an
interconnection.
This requirement was moved from BAL‐005‐0.2b since it does not
Moved from BAL‐005‐0.2b Requirement R1 provide for information regarding the calculation of Reporting ACE.
to FAC‐001‐3 R4 Part 4.3
The requirement is more in line with facilities attaching to an
interconnection.
Exhibit K
BAL-006-2 Mapping Document
Project 2010-14.2.1 Mapping Document
Transition of BAL-006-2
Requirement in
Approved Standard
BAL‐006‐2 R1
BAL‐006‐2 R2
BAL‐006‐2 R3
BAL‐006‐2 R4
BAL‐006‐2 R5
Standard: BAL‐006‐2 – Inadvertent Interchange
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The SDT is recommending this requirement be retired. This
requirement is completely administrative in nature. It meets the
Retired
Paragraph 81 criteria and is in agreement with the Independent
Experts review findings.
The SDT is recommending this requirement be retired. This
requirement is completely administrative in nature. It meets the
Retired
Paragraph 81 criteria and is in agreement with the Independent
Experts review findings.
This requirement directly impacts the ability to calculate an accurate
Moved to BAL‐005‐1 Requirement R7
Reporting ACE value.
The SDT is recommending this requirement be retired. This
requirement is completely administrative in nature. It meets the
Retired
Paragraph 81 criteria and is in agreement with the Independent
Experts review findings.
The SDT is recommending this requirement be retired. This
requirement is completely administrative in nature. It meets the
Retired
Paragraph 81 criteria and is in agreement with the Independent
Experts review findings.
Requirement in
Approved Standard
Standard: BAL‐006‐2 – Inadvertent Interchange
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
2
([KLELWL
&DOFXODWLQJDQG8VLQJ5HSRUWLQJ$&(LQD7LH/LQH%LDV&RQWURO3URJUDP
CalculatingandUsingReportingACEinaTieLineBiasControlProgram
Introduction:
TieLineBias1(TLB)controlhasbeenusedasthepreferredcontrolmethodinNorthAmericafor75years.Inthe
early1950’sthetermAreaControlError(ACE)wasdevelopedforthespecificimplementationofcoordinatedTie
LineBiascontrolnowinusethroughouttheworld.Thisdocumentprovidesresponsibleentitiesguidelinesfor
usingbothrequiredspecificsandthebestpracticesforcalculatingandusingReportingACE2incoordinationwith
othermeasurestoprovidereliablefrequencycontrol.Whiletheincorporationofthesebestpracticesisstrictly
voluntary;reviewing,revising,ordevelopingaprocessusingthesepracticesishighlyencouragedtopromote
andachievereliabilityfortheBulkElectricSystem.
ThefollowingdefinitionsareincludedintheNERCGlossary:
Definition:
5/11/2015
ActualFrequency
FA
TheInterconnectionfrequencymeasuredinHertz(Hz).
Definition:
5/11/2015
ActualNetInterchange
NIA
ThealgebraicsumofactualmegawatttransfersacrossallTieLines,includingPseudoͲTies,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection.ActualmegawatttransfersonasynchronousDC
tielinesdirectlyconnectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
1
2
CapitalizedtermsholdthesamedefinitionasintheNERCglossarythroughoutthisdocument.
TheCPS1measurewasamongthefirstoftheresultsbasedmeasuresdevelopedbyNERC.Itdefinednothowtoperform
control,butinsteaddefinedthetargetcontrolresultsthatweretobeachieved,andamethodtomeasurewhetherornot
thatdefinedcontroltargethadbeenmet.Asaresult,whenCPS1wasimplemented,theACEEquationusedinthat
measurewasalsospecifiedwithinthatstandard.
Historically,AreaControlError(ACE)hasbeenusedtodescribemanytermsinvolvedinTLBControl.WithinaBAA’s
AutomaticGenerationControl(AGC)algorithmtheremaybemorethanoneACEvalueinuse.Insomesystems,theACE
isfilteredpriortodeterminingcontrolactionsinordertosmooththecontrolsignals;or,theremaybeadditional“feedͲ
forward”termsaddedtoACEinanticipationoffuturechanges(e.g.anticipatedramps,changesinambientlightat
sunriseorsunset).TheremaybegaintermsthatmodifycertainvariablessuchastheFrequencyBiasSettingtoimprove
thequalityofcontrolforthespecificcharacteristicsofthatparticularBAA.
SomeauditorshaveraisedcomplianceissuerelatedtotheuseofsuchmodificationstotheACEusedwithintheLoadͲ
FrequencyControl(LFC)system(alsoreferredtoasAGC)andrequiredchangesintheAGCsystemtoconformtothe
definitionofACEinBALͲ001.Theterm“ReportingACE”wasdevelopedandisusedinplaceofthetermACEtoprovidea
consistentperformancemeasurementusingReportingACEandtoremoveanyunnecessaryrestrictionsonthe
specificationofACEwithintheLFCsystem.
1
2
Definition:
AutomaticTimeErrorCorrection
IATEC 5/11/2015
TheadditionofacomponenttotheACEequationfortheWesternInterconnectionthatmodifiesthecontrol
pointforthepurposeofcontinuouslypayingbackprimaryInadvertentInterchange(PII)tocorrect
accumulatedtimeerror.AutomaticTimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Τࢌࢌࢋࢇ
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ࡵ܂ۯ۳۱
ሺି܇ሻכ۶
whenoperatinginAutomaticTimeErrorCorrectionmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
x
x
x
x
x
x
x
x
x
x
x
x
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAAbetween0.2*|Bi|andL10,0.2*|Bi|LmaxL10.
L10ൌ ͳǤͷ ߝ כଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare(RMS)
valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragivenyear.The
bound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
Y=Bi/BS.
H=NumberofhoursusedtopaybackprimaryInadvertentInterchangeenergy.ThevalueofHissetto3.
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactual–Bi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor,
where:
ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontimemonitorcontrol
centerclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲPeak
accumulationaccountingisrequired,
where:
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
Definition:
FrequencyBiasSetting
B
4/1/2015
Anumber,eitherfixedorvariable,usuallyexpressedinMW/0.1Hz,includedinaBalancingAuthority’sArea
ControlErrorequationtoaccountfortheBalancingAuthorityArea’sinverseFrequencyResponsecontribution
totheInterconnection,anddiscourageresponsewithdrawalthroughsecondarycontrolsystems.
3
Definition:
5/11/2015
InterchangeMeterError
IME
Aterm,normallyzero,usedintheReportingACEcalculationtocompensatefordataorequipmenterrors
affectinganyothercomponentsoftheReportingACEcalculation.
Definition:
ReportingACE
RACE 5/11/2015
ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError(ACE)measuredinMWincludes
thedifferencebetweentheBalancingAuthorityArea’sActualNetInterchangeanditsScheduledNet
Interchange,plusitsFrequencyBiasSettingobligation,pluscorrectionforanyknownmetererror.Inthe
WesternInterconnection,ReportingACEincludesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
=
ActualNetInterchange.
x NIA
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
=
AutomaticTimeErrorCorrection.
x IATEC
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciplesofTieͲlineBias
(TLB)ControlandrequiretheuseofanACEequationsimilartotheReportingACEdefinedabove.Any
modification(s)tothisspecifiedReportingACEequationthatis(are)implementedforallBAAsonan
Interconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBiascontrolwillprovidea
validalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’
generation,load,andlossisthesameastotalInterconnectiongeneration,load,andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimesandthesumof
allBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEtermcorrectsforknown
meteringorcomputationalerrors.)
4
Definition:
3/16/2007
ScheduledFrequency
FS
60.0Hz,exceptduringamanualTimeErrorCorrection.
Definition:
5/11/2015
ScheduledNetInterchange
NIS
Thealgebraicsumofallscheduledmegawatttransfers,includingDynamicSchedules,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection,includingtheeffectofscheduledramps.
ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromScheduledNetInterchange.
Structure:
TheeffectiveuseofReportingACEwithinaTLBcontrolprogramshouldaddressthefollowingcomponents:
(I)
(II)
(III)
(IV)
(V)
(VI)
(VII)
(VIII)
ManagementRolesandExpectations
InformationTechnologyRoles
SystemOperatorRoles
ManualSourceDataEntry
AutomaticallyCollectedSourceData
UsesofReportingACE
HistoricDataManagement
SpecialConditionsandCalculations
Eachindividualcomponentshouldaddressprocessesandprocedures,evaluationofanyissuesorproblems
alongwithsolutions,testing,training,andcommunications.Theseprovisionsandactivitiestogetherwillbe
referredtoastheTieLineBiascontrolprogram.
EachresponsibleentityshouldevaluateallofitsusesforReportingACEinitsoperationsanditsreliability
measurement.ReportingACEisoneofthemostimportantsinglemeasurementsavailabletoindicatethe
currentstateoftheResponsibleEntity’scontributiontointerconnectionreliability.3ReportingACEisalsoused
asanintegralpartofthemeasurementsusedinBALͲ001andBALͲ002.Technicalrequirementsassociatedwith
theparametersusedinthecalculationofReportingACEarespecifiedinBALͲ003andBALͲ005.
I.
ManagementRolesandExpectations
ManagementplaysanimportantroleinmaintaininganeffectiveTLBcontrolprogram.The
managementroleandexpectationsbelowprovideahighͲleveloverviewofthecoremanagement
responsibilitiesrelatedtoeachTieLineBiascontrolprogram.Themanagementofeachresponsible
entityshouldtailortheserolesandexpectationstofitwithinitsownstructure.
a. Setexpectationsforsafety,reliability,andoperationalperformance.
3
WhenconfiguredwithaFrequencyBiasSettingequaltotheactualFrequencyResponseoftheBAA,ReportingACEwill
reflecttheBAA’sobligationtomatchitsactualinterchange,lesstheimpactfromitscurrentFrequencyResponseoffset,
toitsscheduledinterchange.
5
b.
c.
d.
e.
II.
AssurethataTLBcontrolprogramexistsforeachresponsibleentityandiscurrent.
ProvideannualtrainingontheTLBcontrolprogramanditspurposeandrequirements.
EnsuretheproperexpectationofTLBcontrolprogramperformance.
Shareinsightsacrossindustryassociations.
InformationTechnology(IT)Roles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEandsourceinformationarealwayscurrentandcorrect.
c. ImplementtheTLBcontrolprograminRealͲtime.
d. EnsurethattheEMSsupportsthemanualdataentryofallsourcedatarequiredtobeenteredbyIT
staff,systemoperationsstaff,andSystemOperatorsandproperlymanagesthatdataonceentered.
e. EnsurethattheEMSsupportsandmanagestheautomaticcollectionofallsourcedatathatis
requiredtobemeasuredinrealͲtimethroughtelemetryanddataexchangeincludingdataquality
informationtoindicatedatavalidity.
f. EnsurethattheprogramsthatmanagedatausedtocalculatecomponentsofReportingACE,
ReportingACEitself,andsubsequentmeasuresbasedonReportingACEareuptodateandcorrect
asidentifiedby,butnotlimitedtothefollowingcalculationsandequations:
1) ActualNetInterchange4(NIA):
AllBAAsinvolvedaccountforthepowerexchangeandassociatedtransmissionlossesasactual
interchangebetweentheBAAs,bothintheirACEandReportingACEequationsandthroughout
alloftheirenergyaccountingprocesses.
i. Calculateforeachscan.5
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
4
Bydefinition“ActualmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromActualNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielinesconnectedto
anotherinterconnectionisprovidedin“SpecialConditionsandCalculations”sectionofthisdocument.
5
ActualNetInterchangescanͲratevaluesarealsousedasoneoftheprimaryinputstothecalculationofFrequency
ResponseMeasure(FRM)onFRSForm1andFRSForm2.
6
2) ScheduledNetInterchange6(NIS):
i. Calculateforeachscan.
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
(Thisvaluediffersfromtheblockaccountingvalue.)
Note: DynamicSchedulesaretobeaccountedforasInterchangeSchedulesbythesource,
sink,andcontractintermediaryBAA(s),bothintheirrespectiveACEandReportingACE
equations,andthroughoutalloftheirenergyaccountingprocesses.
3) FrequencyError('F=(FA–FS)):
i. Calculateforeachscan.
ii. CalculateclockͲminuteaveragefromvalidsamplesavailablewithineachclockͲminute7
whereatleasthalfofthescanͲratesamplesarevalid.
4) FrequencyTriggerLimit–Low(FTLLow)8:
CalculatetheFrequencyTriggerLimit–LowforeachclockͲminutewhereatleasthalfofthescan
ratesamplesarevalidbysubtractingthreetimesEpsilon1fromtheScheduledFrequency(FS).
5) FrequencyTriggerLimit–High(FTLHigh)9:
CalculatetheFrequencyTriggerLimit–HighforeachclockͲminutewhereatleasthalfofthe
scanratesamplesarevalidbyaddingthreetimesEpsilon1totheScheduledFrequency(FS).
6) AccumulatedprimaryInadvertentInterchange(PII):CalculatedeachhourforWECCBAAsonly.
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
7) AutomaticTimeErrorCorrection(IATEC):CalculateforeachhourforWECCBAAsonlyfor
inclusionintheACEandReportingACEEquationforthenexthour.
Τࢌࢌࢋࢇ
ࡵ܂ۯ۳۱
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ሺିࢅሻࡴכ
whenoperatinginATECmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
6
Bydefinition“ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherinterconnection
areexcludedfromScheduledNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielines
connectedtoanotherinterconnectionisprovidedinthe“SpecialConditionsandCalculations”sectionofthisdocument.
7
ClockͲminuteaveragesareusedforthecalculationofACEandFrequencyErrorinCPS1andBAALtoeliminatethe
transientvariationsoftieͲlineflowsandfrequencyerrorusedinthecalculationofperformancemeasures.TheoneͲ
minuteperiodwaschosenbecauseitisevenlydivisiblebyallwholeͲsecondscanrateslessthanthemaximumspecified
scanrateofsixseconds.ThisassuresgreatercomparabilityofperformancedataamongBAswithdifferentscanrates.
8
Thisvariablecouldbeenteredmanuallyaslongasitischangedeverytimeamanualtimeerrorcorrectionisstartedor
stopped.Ifmanualtimeerrorcorrectioniseliminated,itcouldbecomeaconstantandenteredmanually.
7
8) ReportingACE:
i. Calculateforeachscan.
ii. CalculatedaverageforeachclockͲminuteforBAAsusingafixedFrequencyBiasSetting
whenatleasthalfofthevaluesarevalid.9
9) ComplianceFactor10:
i. CalculateforeachscanwherebothReportingACEandFrequencyErrorarevalid.
ii. CalculateforeachclockͲminutewhereboththeaverageclockͲminuteFrequencyErrorand
theaverageclockͲminuteReportingACEarevalid.11
10) ClockͲhourcompliancefactor8:
CalculateforeachhourbysummingthevalidclockͲminutecompliancefactorsforthehourand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthehour.
11) Monthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthemonthanddividingby
thenumberofvalidclockͲminutecompliancefactorsinthemonth.
12) 12Ͳmonthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthe12Ͳmonthperiodand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthe12Ͳmonthperiod.
13) CPS1compliancefactor:
CalculatetheCPS1compliancefactorbydividingthe12Ͳmonthcompliancefactorbythesquare
oftheEpsilon1valuefortheInterconnection.
14) CPS1:
i. CalculatetheCPS1scanrateperformancebydividingthescanratecompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachscanwitha
validcompliancefactor.
ii. CalculatetheCPS1clockͲminuteperformancebydividingtheclockͲminutecompliance
factorbythesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthat
valuefrom2andmultiplyingtheresultby100toconverttoapercentageperformancefor
eachclockͲminutewithavalidcompliancefactor.
iii. CalculatetheCPS1clockͲhourperformancebydividingtheclockͲhourcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
9
TheaverageofthevalueoftheratioofthescanratevalueofReportingACEdividedbythescanratevalueofͲ10times
theFrequencyBiasSettingforthoseBAsusingavariableFrequencyBiasSetting,whereatleasthalfoftheratiovalues
arevalid.
10
UsedforCPS1.
11
ThecompliancefactoriscalculatedwhentheaverageofthevalueoftheratioofthescanratevalueofReportingACE
dividedbythescanratevalueofͲ10timestheFrequencyBiasSettingforthoseBAsusingavariableFrequencyBias
Setting,whereatleasthalfoftheratiovaluesarevalidandtheaverageclockͲminuteFrequencyErrorisvalid.
8
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
iv. CalculatetheCPS1monthlyperformancebydividingthemonthcompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲminute
withavalidcompliancefactor.
v. CalculatetheCPS112Ͳmonthperformancebydividingthe12Ͳmonthcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
15) BalancingAuthorityACELimitͲLow(BAALLow):
i. CalculatethescanrateBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
16) BalancingAuthorityACELimitͲHigh(BAALHigh):
i. CalculatethescanrateBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
17) BalancingAuthorityACELimitͲLowCompliance:
i. AlarmBAALLowpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisbelowtheclockͲminuteBAALLow.
ii. IndicateBAALLownonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
belowtheclockͲminuteBAALLowformorethan30ͲconsecutiveclockͲminutes.
18) BalancingAuthorityACELimitͲHighCompliance:
i. AlarmBAALHighpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisabovetheclockͲminuteBAALHigh.
ii. IndicateBAALHighnonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
abovetheclockͲminuteBAALHighformorethan30consecutiveclockminutes.
g. EnsurethattheEMSsupportstheretentionofallhistoricdataincludingdataqualityinformation
requiredtoberetainedtosupportcontinuingoperationsandauditrequirements.
9
h. EnsurethattheEMSsupportsandmanagesthepresentationofallinformationrequiredtobe
availabletotheSystemOperatorforrealͲtimeoperations,operationsstaffforevaluationof
operations,andauditorsforcomplianceconfirmation.
i.
ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
III.
SystemOperatorandOperationsStaffRoles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEinformationisalwayscurrentandcorrect.
c. ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
d. ImplementtheTLBcontrolprograminRealͲtime.
IV.
ManualSourceDataEntry
ReportingACEiscalculatedinRealͲtime,atleasteverysixseconds12,bytheResponsibleEntity’sEnergy
ManagementSystem(EMS),andmaybepartiallybasedonsourcedatamanuallyenteredintothat
system.Thefollowingsourcedatamaybeentered:
NIA(ActualNetInterchange):Thetelemetryvaluesofactualtieflows,includingpseudoͲties,between
AdjacentBalancingAuthorityAreasmaynotbeavailablefromanautomaticcollectionsource,
requiringmanualentryofestimatedflows.Thesemanualentriesshouldbeperformedina
mannerthatreasonablyassuresequalmagnitudeandoppositesignvaluesareusedbythe
AdjacentBalancingAuthorityAreasenteringthemanualdata.Iftheactualflowestimatesare
thesamefortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedto
thetwoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failureto
matchactualflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
NIS(ScheduledNetInterchange):Thepowertransferschedules,includingtheschedulerampswhere
applicable,areprocessedbytheEMS.Ifscheduledflowestimatesareequalandhaveopposite
signsfortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedtothe
twoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failuretomatch
scheduledflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
B(FrequencyBiasSetting):TheFrequencyBiasSetting,orminimumrequiredvalue,fortheBalancing
AuthorityAreaisspecifiedbycalculationsperformedaspartofcompliancewithBALͲ003Ͳ1Ͳ
FrequencyResponseandFrequencyBiasSetting;
R2.
EachBalancingAuthorityAreathatisamemberofamultipleBalancingAuthority
AreaInterconnectionandisnotreceivingOverlapRegulationServiceandusesafixed
FrequencyBiasSettingshallimplementtheFrequencyBiasSettingdeterminedin
accordancewithAttachmentA,asvalidatedbytheERO,intoitsAreaControlError
12
BALͲ005Ͳ1BalancingAuthorityControlͲR2.TheBalancingAuthorityshallusenogreaterthanasixͲsecondscanratein
acquiringdatanecessarytocalculateReportingACE.
10
(ACE)calculationduringtheimplementationperiodspecifiedbytheEROandshall
usethisFrequencyBiasSettinguntildirectedtochangebytheERO.13
10isthefactor(100.1Hz/Hz)thatconvertstheFrequencyBiasSettingunitstoMW/Hz.
FS(ScheduledFrequency):ScheduledFrequency,normally60Hz,ismanuallyadjustedonacoordinated
basiswhendirectedtodosobytheInterconnectionTimeMonitorasspecifiedinBALͲ004Ͳ0.14It
isimportantforallBAAsonaninterconnectiontomaketheseadjustmentsonacoordinated
basissothatallBAAsarecontrollingtothesameScheduledFrequencyatalltimes.
IME(InterchangeMeterError):Thisterm,normallyzero,isavailableforusebytheSystemOperatoror
operationsstafftoaddacorrectiontermintheReportingACEcalculationtocompensatefor
dataorequipmenterrorsaffectinganyothercomponentsidentifiedbyanalysisofhistoricdata
demonstratingtheexistenceoferrors,usuallyerrorsbetweenintegratedhourlyscanͲratedata
andhourlyagreedtoaccumulatedmeterdata.(SeetheSpecialConditionsandCalculations
sectionofthisdocumentforadditionalinformation)
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|B|andL10,0.2*|B|чLmaxчL10.
YisnormallycalculatedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.
Hisnormallysetto3andusedbytheATECprogramintheEMSforBAsontheWestern
Interconnection.Itrepresentsthenumberofhoursoverwhichtheprimaryinadvertent
interchangeispaidback.
BSisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Itrepresentsthe
sumoftheminimumFrequencyBiasSettingsforallBAAsontheInterconnection.
ȴTEisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Insomecases,it
maybecalculatedbytheEMSbasedonthefactorsintheȴTEequation.ȴTEisthehourly
changeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor.
TDadjisanadjustmentforthedifferencesbetweenthelocalclockinthelocaltimestandardandthe
InterconnectiontimemonitorcontrolcenterclockssothatthelocalEMScancalculatethe
correctȴTEfortheBAAsandusedbytheATECprogramintheEMSforBAAsontheWestern
Interconnection.
TEoffsetisenteredasinstructedbytheInterconnectiontimemonitor.
H1istheRMSLimitforthe1Ͳminuteaveragefrequencyerrorfortheinterconnection.
13
Asanoteofinterest,thenewproceduresputforthwithBALͲ003Ͳ1willresultinthereductionofminimumFrequency
BiasSettingvaluesonthemultipleBAinterconnectionstobringthemclosertothenaturalmeasuredFrequency
Responseoftheinterconnection.TherulerequiringaminimumFrequencyBiasSettingof1%ofpeakloadintheNERC
Standardsdatesbackto1962whenNAPSIC,theprecursortotheNERCOperatingCommittee,codifiedthe
recommendationsoftheInterconnectedSystemsGroupmadein1956tosetaminimumof50%ofthenaturalmeasured
responsewhichwas2%ofpeakloadatthattime.The1%figureisnowmorethan200%ofthenaturalmeasured
responsefortheEasternInterconnectionandinsomecasesisapproachingavaluethatcouldresultininstabilitybybeing
toohigh.Thelogicjustifyingaminimumofthenaturalresponseisstillvalid.
14
Thisisconsistentwithcondition3intheReportingACEDefinition:“TheuseofacommonScheduledFrequencyFSforall
areasatalltimes.”
11
V.
AutomaticallyCollectedSourceData
ReportingACEiscalculatedinRealͲtime,atleastasfrequentlyaseverysixseconds15,bytheresponsible
entity’sEnergyManagementSystem(EMS)predominantlybasedonsourcedataautomaticallycollected
bythatsystem.Also,thedatamustbeupdatedatleasteverysixsecondsforcontinuousscantelemetry
andupdatedasneededforreportͲbyͲexceptiontelemetry.
Inaddition,dataqualityinformation(usuallyintheformofdataqualityflagsassociatedwitheachdata
value)mustberetainedandpresentedinrealͲtimetotheSystemOperators.Thisdataquality
informationispresentedtotheSystemOperatortohavesituationalawarenesswithrespecttothe
qualityofthedatainputsandfinalcalculatedresult.Itislaterusedtodeterminewhichdataisvalidfor
useinperformancecalculationssuchasCPS1,BAAL,DCS,andfrequencyresponseobligation(FRM).
NIA(ActualNetInterchange):ThetieͲlinevaluerepresentingeachtieͲlineflowandpseudoͲtiequantity
iscollectedattherequiredscanrateofsixsecondsorless.16,17,18,19Datathatisofquestionableaccuracy
ortimelinessisflaggedwithanappropriatedataqualityflag.Thisinformationispresentedtothe
SystemOperatortosupportsituationalawareness.20TheEMSsumstheindividualflowvaluesonalltie
linesandpseudotieswithalladjacentBAAsatthescanrateandincludesthisvalueasNIAinthe
ReportingACEequationcalculation.TheresultisaseriesofNIAvaluesattheEMSscanrateand
associateddataqualityflags.Theassociateddataqualityofthetelemetryelementispassedtothe
resultofallcalculationsusingthatelement.
NIS(ScheduledNetInterchange):MostinterchangeschedulesandsomeDynamicSchedulesare
enteredintotheEMSinasummaryformateitherasindividualschedules,schedulenetswitheach
AdjacentBalancingAuthorityArea,orafinalScheduledNetInterchange.Theseschedulesareconverted
intoscanͲrateschedulesbytheEMS.TheEMScalculatestheScheduledNetInterchange,where
applicable,bysummingallindividualschedulevaluesornetswitheachAdjacentBalancingAuthority
AreaforallregularandDynamicSchedulesandincludestheresultasNISintheACEequation.
FA(ActualFrequency):Actualfrequencyisprovidedbyafrequencymeasuringdeviceattheaccuracy
specifiedinBALͲ00521attheEMSscanrate.Ifafrequencyvalueisnotavailable,thevalueforthatscan
ismarkedinvalid.
15
BALͲ005Ͳ1BalancingAuthorityControl–“R2.TheBalancingAuthorityAreashallusenogreaterthanasixͲsecondscan
rateinacquiringdatanecessarytocalculateReportingACE.”
16
DatatransmittedatarateslowerthanthescanrateoftheremotesensingequipmentmayrequiretheinclusionofantiͲ
aliasingfilteringatthesourceofthemeasurementtoeliminatetheriskofaliasinginthedatatransmittedtotheEMS.
Seetheattacheddocumenttitled“AntiͲaliasingFiltering.”
17
ItisacceptabletocollecttieͲlineflowdatafromRTUsthatusereportbyexceptionaslongasthoseRTUscansupportthe
scanrateofsixsecondsorlesswhendataischangingrapidlyandbothadjacentBAAsarereceivingcomparabledatato
keepthemeasuredflowsequivalent.
18
ThesixͲsecondscanratenotonlyassuresthatdatacollectedisclosetoRealͲtime,italsolimitsthelatency(timeskew)
associatedwiththedatacollection.
19
Theaccuracyoftheflowdataissetbythoseusingtheflowdatafortransmissionflowmanagement.AswithallACEdata,
aslongasbothadjoiningBAAsareusingthesamevaluesfortieͲlineflow,theeffectsofanyerrorinflowmeasurement
willbeconfinedtothetwoadjacentBAAs.
20
Indicationsofsuspectdataareusuallyindicatedwithcolorchangesand/oralarms.
21
BALͲ005–AutomaticGenerationControlspecifiesanaccuracyofч0.001Hz(equivalenttoч+/Ͳ0.0005Hz)fortheDigital
FrequencyTransducer.
12
IIactual(InadvertentInterchange):ThistermisonlyusedintheWesternInterconnectionACEcalculation.
InadvertentInterchange“Actual”fortheprevioushouriscalculatedbytheEMSfromtheprevious
hour’sdataasthedifferencebetweentheintegratedhourlyaverageScheduledNetInterchangeandthe
integratedhourlyaverageActualNetInterchange.(Blockschedulesarenotusedforthiscalculation.)
t(ManualTimeErrorcorrectionminutesinthehour):ThenumberofminutesofmanualTimeError
correctioninthehour.
VI.
UsesofReportingACE
a. ReportingACEiscurrentlyusedtomeasuresecondaryfrequencycontrolwithinTLBcontrolonallof
theInterconnections.22Consequently,ReportingACEisoneoftheprimarymeasurement
parametersinmanyoftheNERCBalancingStandards.Thefollowingstandardsrequiretheuseof
ReportingACEaspartoftheperformancemetricsorsetrequirementsassociatedwiththe
calculationofReportingACE.
i. BALͲ001Ͳ1–RealPowerBalancingControlPerformanceandBALͲ001Ͳ2–RealPowerBalancing
ControlPerformance.
ii. BALͲ002Ͳ1–DisturbanceControlPerformanceandBALͲ002Ͳ2–DisturbanceControlStandard–
ContingencyReservefromaBalancingContingencyEvent(whenapproved).
iii. BALͲ005Ͳ0.2b–AutomaticGenerationControlandBALͲ005Ͳ1–BalancingAuthorityControl
(whenapproved).
iv. BALͲ006Ͳ2InadvertentInterchange.
b. TheindustrymayalsoconsidertheuseofReportingACEinthefuturetoevaluatetherules
associatedwithtransmissionloading.
VII.
VIII.
IX.
HistoricDataManagement
TheindustrycurrentlyrequirestheretentionofdatasupportingthecalculationofReportingACEand
compliancemeasurementsbasedinpartonReportingACEtosupporttheNERCcomplianceaudit
process.ThisdataretentionmustbeconsideredasanintegralpartoftheReportingACEand“TLB
controlprogram”.
SpecialConditionsandCalculations
IME(InterchangeMeterError):BALͲ005Ͳ1R6requires,“EachBalancingAuthorityAreathatiswithina
multipleBalancingAuthorityAreainterconnectionshallimplementanOperatingProcesstoidentifyand
mitigateerrorsaffectingthescanͲrateaccuracyofdatausedinthecalculationofReportingACE.”
Ideally,errorsidentifiedshouldbecorrectedimmediately,butthisisnotalwayspossible.TheIMEterm,
normallyzero,canbeusedbytheSystemOperatororoperationsstafftoaddacorrectionterminthe
ReportingACEcalculationcorrectingerrorsaffectingthescanͲrateaccuracyofdata,thusmitigatingthe
errorinthecalculationofReportingACEuntiltelemetryerrorscanbecorrected.
22
OnsingleBAAInterconnections,theACEEquationreducestoasingleterm,Ͳ10B(FA–FS),becausetherearenotielines
orschedulestoincludeinthefirstterm,(NIA–NIS),andthereisnoIMEtermtocorrectfortielineordynamicschedule
measurementerrorsinthefirstterm.
13
ThecalculationoftheIMEistheoneoftheresultsofthisrequiredOperatingProcess.It
compensatesfordataorequipmenterrorsaffectingcomponentsofReportingACEidentifiedby
analysisofhistoricdata.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataand
hourlyaccumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulatedmeter
dataoftwoadjacentBAAs.TheprocessusedforincludingadjustmentsintheIMEtermshouldbe
basedongoodqualitycontrolmethods.23
ThegoalassociatedwiththeuseoftheIMEistoencouragethescanͲratevaluesofactualand
scheduledinterchangebetweenAdjacentBalancingAuthoritiestobeequalinmagnitudeandhave
oppositesigns.24Unfortunately,thesevaluescannotbedirectlycomparedwitheachotherbecause
ofdifferencesbetweenscantimeanddifferencesbetweenscanͲratesbetweenBAAs.Wheninitially
configured,allBAsused“DigitaltoAnalog”convertersand“AnalogtoDigital”converterstotransmit
tieͲlineflowsandaccumulatedMWhvaluesfromthecommonmeteringpointrequiredinthe
standardstotheBA’sEMS.These“DtoA”and“AtoD”convertersaresubjecttoerrorandrequire
frequentcalibration,andalthough,manyhavebeenreplacedbydigitaltelemetry,theystillexistand
requireoversight.AnydifferencebetweenthescanͲratevaluesagreedtobyAdjacentBAAsthatis
notincludedintheerrormitigationprocesswillbepassedtotheinterconnectionformanagement
andwillnotbeincludedintheperformancemeasuressuchasCPS1,BAALandFRM.
EnergyManagementSystemsarecapableofintegratingthescanͲratevaluesusedforthecalculation
ofReportingACEandprovidingthoseintegratedvaluesforcomparisontotheaccumulated
megawattͲhourvaluesforthesamemeters.Iftheintegratedscanratevaluesareclosetothe
accumulatedmegawattͲhourvalues,thenonecanconcludethatthescanͲratevaluesaccurately
representtheaccumulatedvalues.Thefinalstepinthisprocessincludesacomparisonand
agreementontheaccumulatedmegawattͲhourvaluesbetweentheAdjacentBAAssharingthe
measurement.IfthedifferencesbetweenaccumulatedvaluesbetweenAdjacentBAAsisnot
includedinthisprocess,anyadjustmentstotheaccumulatedvaluesmadebyaBAAtoachieve
agreementwithanadjacentBAAwillbeexcludedfromtheanalysisandwillnotbemitigated.This
informationusedinconjunctionwithasimilaranalysisofthescanratevaluesforthesame
measurementbytheAdjacentBalancingAuthorityAreaincludinganalysisofanydifferences
betweentheaccumulatedvaluesandtheagreedtoaccumulatedvalues.Thistotalprocessprovides
reasonableassurancethatthescanͲratetielineflowsorthedynamicschedulesusedbyAdjacent
BAAsareconsistentwithoneanotherconfiningcontrolproblemswithintheboundariesofthe
AdjacentBAAs.
23
AdjustmentstotheIMEtermshouldfollowgoodqualitycontrolmethodsandexcludetamperingasdemonstratedbythe
Deming’sFunnelExperiment,http://blog.newsystemsthinking.com/wͲedwardsͲdemingͲandͲtheͲfunnelͲexperiment/.
24
AslongasthescanͲratetielineflowsandscheduledflowsmatchforAdjacentBalancingAuthorityAreas,anyproblems
withthemeasurementofbalancingontheinterconnectionwillbeconfinedtowithintheboundariesofthoseAdjacent
BalancingAuthorityAreas.Anymismatchwillpassthedifferencetotheinterconnectionandwillresultinfrequency
controlerrorthatwilltobeexcludedfromperformancemeasurementandmanagedbyallBAAsthroughthefrequency
biastermsoftheirReportingACE.
14
TheseerrorcorrectionadjustmentscanbeusedtocorrecterrorsintheNIAorNIS25termsfor
ReportingACEandothermeasurementsthatdependuponanaccurateActualNetInterchange
and/oranaccurateScheduledNetInterchange.Thesamelogicandevaluationprocessesthatare
validforinclusionintheIMEtermoftheReportingACEequationshouldalsobevalidasadjustments
tothescanratetieͲlineflowsusedforthemeasurementofFrequencyResponseaspartoftheBALͲ
003Ͳ1.
a. UseofSourceͲSinkPairsforAsynchronousDCTieLinestoAnotherInterconnection:Oneofthe
primaryrulesforinsuringthevalidityoftheReportingACEequationis,“Allportionsofthe
InterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’generation,load,and
lossisthesameastotalInterconnectiongeneration,load,andloss.”Thisisaccomplishedby
requiringtheinclusioninReportingACEofalltielines,pseudoties,interchangeschedulesand
DynamicSchedulestoAdjacentBalancingAuthorityAreasandonlyAdjacentBalancingAuthority
AreasonthesameInterconnection,andrequiringtheexclusionofallasynchronousDCtielinesand
associatedscheduledinterchangewithBalancingAuthorityAreasonadifferentInterconnection
fromReportingACE.Followingthissimpleruleinsuresthatallloads,lossesandgenerationare
properlyincludedwitheachInterconnection.
InsteadofincludingthepowertransfersfromanasynchronousDCtielinebetweentwo
InterconnectionsasanormalinterchangetransferbetweentwoBAAs,thisformofpowertransfer
shouldbeincludedasthoughitisalinkedsourceͲsinkpairforthepurposesofmanagingfrequency
controlwithinatielinebiascontrolprogram.OneterminalofanasynchronousDCtielinewill
appeartothereceivingInterconnectionandreceivingBAAasanenergyresourcesimilartoa
generator.ThisisthesourceendofthesourceͲsinkpair.Theotherterminalofthesame
asynchronousDCtielinewillappeartothesupplyingInterconnectionandsupplyingBAAasan
energysinksimilartoaload.ThisisthesinkendofthesourceͲsinkpair.
InterchangetransactionslinkedtoeitherthesourceorsinkfromotherBAAsonthesame
Interconnectionasthesourceorsinkwillschedulethosetransactions,includethosetransactionsin
ReportingACE,andmanagethosetransactionsinasimilarmannertoanyotherenergytransaction.
OnlytheBAAactingasthesourceorthesinkfortheDCtielinewillexcludetheasynchronoustie
linefromitsReportingACEwhileincludingalltransactionswithAdjacentBAAsonthesame
InterconnectionassociatedwiththatsourceorsinkpowertransferintheirReportingACE.
25
ErrorsintheNISwouldonlyoccurandonlysupportcorrectionincaseswherethereisameasurementerrorassociated
withaDynamicSchedule.
Exhibit M
Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672, the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. 1 The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria.
1.
Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
The proposed Reliability Standards BAL-005-1 and FAC-001-3, attached as Exhibit A
and Exhibit B, respectively, achieve specific reliability goals using sound methods to achieve
those goals. First, Reliability Standard BAL-005-1 accomplishes the goal of “establishing
requirements for acquiring data necessary to calculate Reporting Area Control Error (Reporting
ACE)” and specifying “a minimum periodicity, accuracy, and availability requirement for
acquisition of the data and for providing the information to the System Operator.” The proposed
standard accomplishes that goal by identifying all information necessary to calculate Reporting
ACE so that the balancing of resources and demand can be achieved under Tie-Line Bias Control
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment,
Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order
on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321 (“The proposed Reliability Standard must address a reliability concern that falls within
the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.”).
Order No. 672 at P 324 (“The proposed Reliability Standard must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve this goal. Although any person may propose a topic for a
Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should be
developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.”).
and requiring applicable entities to acquire that information for those calculations. Second,
proposed Reliability Standard FAC-001-3 accomplishes the goal of avoiding “adverse impacts
on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator
Owners.” The proposed standard accomplishes this goal by setting forth interconnection
requirements for each entity that has Facility interconnection requirements.
2.
Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
Proposed Reliability Standards BAL-005-1 and FAC-001-3 are clear and unambiguous as
to what is required and who is required to comply, in accordance with Order No. 672.
The proposed Reliability Standards clearly articulate the actions that such entities must
take to comply with the standard, each of which are triggered by specific actions and situations.
Further, each requirement of the proposed Reliability Standards clearly states who is required to
comply with that requirement. Proposed Reliability Standard BAL-005-1 applies to Balancing
Authorities, and proposed Reliability Standard FAC-001-3 applies to Transmission Owners and
Applicable Generator Owners. As defined in the Applicability section of the standard document,
attached herein as Exhibit B, an Applicable Generator Owner is a “Generator Owner with a fully
executed Agreement to conduct a study on the reliability impact of interconnecting a third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.”
3
Order No. 672 at P 322 (“The proposed Reliability Standard may impose a requirement on any user, owner, or
operator of such facilities, but not on others.”).
Order No. 672 at P 325 (“The proposed Reliability Standard should be clear and unambiguous regarding what is
required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know what
they are required to do to maintain reliability.”).
2
3.
A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factors (“VRF”) and Violation Severity Levels (“VSL”) for
proposed Reliability Standards BAL-005-1 and FAC-001-3, attached as Exhibit G and Exhibit
H, respectively, comport with NERC and Commission guidelines related to their assignment.
The assignment of the severity level for each VSL is consistent with the corresponding
Requirement and the VSLs should ensure uniformity and consistency in the determination of
penalties. The VSLs do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations. For these reasons, the
proposed Reliability Standards include clear and understandable consequences in accordance
with Order No. 672.
4.
A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non
preferential manner. 5
Proposed Reliability Standard BAL-005-1 contains seven measures that support each of
the seven requirements by clearly identifying what is required to demonstrate compliance and
how each Requirement will be enforced. The Measures are as follows:
M1. Each Balancing Authority will have dated documentation demonstrating that the
data necessary to calculate Reporting ACE was designed to be scanned at a rate of no
more than six seconds. Acceptable evidence may include historical data, dated archive
files; or data from other databases, spreadsheets, or displays that demonstrate compliance.
M2. Each Balancing Authority will have dated records to show when it was unable to
calculate Reporting ACE for more than 30 consecutive minutes and that it notified its
Reliability Coordinator within 45 minutes of the beginning of the inability to calculate
4
Order No. 672 at P 326 (“The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.”).
5
Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in compliance with
a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so that
it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.”).
3
Reporting ACE. Such evidence may include, but is not limited to, dated voice recordings,
operating logs, or other communication documentation.
M3. The Balancing Authority shall have evidence such as dated documents or other
evidence in hard copy or electronic format showing the frequency metering equipment
used for the calculation of Reporting ACE had a minimum availability of 99.95% for
each calendar year and had a minimum accuracy of 0.001 Hz to demonstrate compliance
with Requirement R3.
M4. Each Balancing Authority Area shall have evidence such as a graphical display or
dated alarm log that provides indication of data validity for the real-time Reporting ACE
based on both the calculated result and all of the associated inputs therein.
M5. Each Balancing Authority will have dated documentation demonstrating that the
system necessary to calculate Reporting ACE has a minimum availability of 99.5% for
each calendar year. Acceptable evidence may include historical data, dated archive files;
or data from other databases, spreadsheets, or displays that demonstrate compliance.
M6. Each Balancing Authority shall have a current Operating Process meeting the
provisions of Requirement R6 and evidence to show that the process was implemented,
such as dated communications or incorporation in System Operator task verification.
M7. The Balancing Authority shall have dated evidence such as voice recordings or
transcripts, operator logs, electronic communications, or other equivalent evidence that
will be used to demonstrate a common source for the components used in the calculation
of Reporting ACE with its Adjacent Balancing Authority.
Proposed Reliability Standard FAC-001-3 contains four measures that support each of the
four requirements by clearly identifying what is required to demonstrate compliance and how
each Requirement will be enforced. The Measures are as follows:
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
4
The above excerpted Measures work in coordination with the respective Requirements to
ensure that the Requirements will each be enforced in a clear, consistent, and non-preferential
manner without prejudice to any party.
5.
Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design. 6
The proposed Reliability Standards achieve the reliability goals effectively and efficiently
in accordance with Order No. 672. Proposed Reliability Standard BAL-005-1 improves
reliability by establishing specific requirements for Balancing Authorities for acquiring
necessary data for calculating Reporting ACE so that balancing of resources and demand can be
achieved under Tie-Line Bias Control. In an effort to consolidate standards, proposed BAL-0051 includes a requirement from currently effective Reliability Standard BAL-006-2 related to
calculating Reporting ACE. Because the other requirements in BAL-006-2 relate to commercial
practices and are not appropriate for a NERC Reliability Standard, BAL-006-2 is proposed for
retirement. Finally, proposed Reliability Standard FAC-001-3 improves reliability by setting
forth all interconnection requirements that require applicable entities to confirm that all Facilities
being interconnected to the Bulk Electric System are within a Balancing Authority Area’s
metered boundaries.
While both of the proposed standards achieve the respective reliability goals effectively
and efficiently, these do not reflect “best practices” that do not take into account implementation
cost or historical regional infrastructure design. Rather, the standard drafting team developing
6
Order No. 672 at P 328 (“The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.”).
5
these standards considered all factors relevant to creating effective, efficient Reliability
Standards.
6.
Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability. 7
The proposed Reliability Standards and definitions do not reflect a “lowest common
denominator” approach. To the contrary, the proposed Reliability Standards represent a
significant improvement over the previous versions as described herein because the proposed
standards streamline requirements, improve language in currently effective standards, and add
requirements needed to ensure proper calculation of Reporting ACE.
7.
Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard. 8
7
Order No. 672 at P 329 (“The proposed Reliability Standard must not simply reflect a compromise in the ERO’s
Reliability Standard development process based on the least effective North American practice — the so-called
“lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.”).
Order No. 672 at P 330 (“A proposed Reliability Standard may take into account the size of the entity that must
comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.”).
8
Order No. 672 at P 331 (“A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.”).
6
The proposed Reliability Standards and definitions apply throughout North America and
do not favor one geographic area or regional model.
8.
Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
The proposed Reliability Standards have no undue negative impact on competition. The
proposed Reliability Standards require the same performance by each applicable entity. The
standards do not unreasonably restrict the available transmission capability or limit use of the
Bulk-Power System in a preferential manner.
9.
The implementation time for the proposed Reliability Standard is reasonable. 10
The proposed effective dates for the proposed Reliability Standards are just and
reasonable and appropriately balance the urgency in the need to implement the standards against
the reasonableness of the time allowed for those who must comply to develop necessary
procedures, software, facilities, staffing or other relevant capability. The proposed
Implementation Plan, attached as Exhibit D, E, and F, will allow applicable entities adequate
time to ensure compliance with the requirements.
10.
The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
9
Order No. 672 at P 332 (“As directed by section 215 of the FPA, FERC itself will give special attention to the
effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed Reliability
Standard that has no undue negative effect on competition. Among other possible considerations, a proposed
Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power System
beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly
preferential manner. It should not create an undue advantage for one competitor over another.”).
10
Order No. 672 at P 333 (“In considering whether a proposed Reliability Standard is just and reasonable, FERC
will consider also the timetable for implementation of the new requirements, including how the proposal balances
any urgency in the need to implement it against the reasonableness of the time allowed for those who must comply
to develop the necessary procedures, software, facilities, staffing or other relevant capability.”).
11
Order No. 672 at P 334 (“Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
7
The proposed Reliability Standards and definitions were developed in accordance with
NERC’s Commission-approved, ANSI- accredited processes for developing and approving
Reliability Standards. Exhibit N includes a summary of the Reliability Standard development
proceedings, and details the processes followed to develop the standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the drafting team were
properly noticed and open to the public. The initial and recirculation ballots both achieved a
quorum and exceeded the required ballot pool approval levels.
11.
NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of
these proposed Reliability Standards and definitions. No comments were received that indicated
the proposed Standards conflict with other vital public interests.
12.
Proposed Reliability Standards must consider any other appropriate factors. 13
No other negative factors relevant to whether the proposed Reliability Standards are just
and reasonable were identified.
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.”).
12
Order No. 672 at P 335 (“Finally, we understand that at times development of a proposed Reliability Standard
may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.”).
13
Order No. 672 at P 323 (“In considering whether a proposed Reliability Standard is just and reasonable, we will
consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.”).
8
([KLELWN
6XPPDU\RI'HYHORSPHQW+LVWRU\DQG&RPSOHWH5HFRUGRI'HYHORSPHQW
Summary of Development History
Summary of Development History
The development record for proposed Reliability Standards BAL-005-1, BAL-006-3,
and FAC-001-3 are summarized below.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to
give “due weight” to the technical expertise of the ERO. 1 The technical expertise of the
ERO is derived from the standard drafting team selected to lead each project in
accordance with Section 4.3 if the NERC Standards Process Manual. 2 For this project,
the standard drafting team consisted of industry experts, all with a diverse set of
experiences. A roster of the standard drafting team members is included in Exhibit O.
II.
Standard Development History
A. Periodic Review Recommendations
A review team was assembled in the fall of 2013 to conduct a periodic review of
Balancing Authority Reliability-based Controls Reliability Standards BAL-005-0-2b and
BAL-006-2. The Balancing Authority Reliability-based Controls Periodic Review Team
(“BARC 2 PRT”) proposed several recommendations, and based upon consideration of
comments, the BARC 2 PRT submitted the recommendations to the NERC Standards
Committee (“SC”) on February 21, 2014 for review.
B. Standard Authorization Request Development
After submitting its recommendations to revise BAL-005-0-2b and BAL-006-2,
the BARC 2 PRT submitted a Standard Authorization Request (“SAR”) and associated
proposed Reliability Standards and associated documents implementing the BARC 2
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2012).
The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
2
1
PRT findings to the SC. The SAR and proposed Reliability Standards were originally
posted for 30-day public comment period from July 16, 2014 through August 14, 2014.
There were 19 sets of responses, including comments from approximately 95 different
individuals from approximately 75 companies representing 9 of the 10 Industry
segments. 3
C. First Posting - Comment Period, Initial Ballot and Non-Binding Poll
Proposed Reliability Standards BAL-005-1, BAL-006-3, and FAC-001-3 were
posted for a 45-day formal comment period from July 30, 2015 through September 14,
2015, with an initial ballot held from September 4, 2015 through September 14, 2015.
Several documents were posted for guidance with the first draft, including the standard
documents, implementation plans, Mapping Documents for BAL-005-1, BAL-006-3,
FAC-001-3, and a White Paper called “Calculating and Using Reporting ACE in a Tie
Line Bias Control Program.” The initial ballot reached quorum at 83.81% of the ballot
pool with 55.97% approval. The Non-Binding Poll reached quorum at 83.64% and the
standard and associated documents received support from 56.90% of the voters. There
were 46 sets of responses, including comments from approximately 131 different
individuals and approximately 87 companies, representing 9 of the 10 industry
segments. 4
3
NERC, Consideration of Comments, Project 2010-14.2 Periodic Review of BAL Standards, (July 2015),
available at
http://www.nerc.com/pa/Stand/Project%2020101421%20Phase%202%20DL/Consideration_of_Comments_201014_2_Periodic_Review_BAL_20150715.pdf.
4
NERC, Consideration of Comments, Project 2010-14.2.1, (Nov. 10, 2015), available at
http://www.nerc.com/pa/Stand/Project%2020101421%20Phase%202%20DL/201014_2_1_Phase_2_of_BARC_BAL-005_and_BAL-006_Consideration_of_Comments_11102015.pdf
2
D. Survey Period for White Paper and Retirement of BAL-006-2
On September 16, 2015, the Inadvertent Interchange Whitepaper, explaining
inadvertent interchange calculations used by industry, as well as a survey concerning the
disposition of BAL-006, were posted for industry comment. According to the BARC 2
SDT, the Independent Expert Review Report and BARC 2 PRT reviewing BAL-005-0.2b
and BAL-006-2, and several industry participants had previously indicated that much of
currently-effective Reliability Standard BAL-006-2 is an energy accounting standard and
not a NERC Reliability Standard. Thus, the survey was intended to gauge how the
industry intended to accommodate the need for energy accounting. There were 14 sets of
responses, including comments from approximately 43 different individuals and
approximately 33 different companies, representing 6 of the 10 Industry Segments. 5
E. Second Posting - Comment Period, Additional Ballots and Non-Binding Polls
Proposed Reliability Standards BAL-005-1, BAL-006-3, and FAC-001-3 were
posted for a 45-day formal comment period from November 10, 2015 through January
11, 2016, with an additional parallel ballot held from December 31, 2015 through January
11, 2016. The additional ballot received for BAL-005-1 reached quorum at 84.13% of the
ballot pool, and the standard and associated documents received support from 70.64% of
the voters. The additional ballot for BAL-006-2 reached quorum at 84.44% of the ballot
pool, and the standard and associated documents received support from 94.30% of the
voters. The additional ballot received for FAC-001-3 reached quorum at 83.17% of the
ballot pool, and the standard and associated documents received support from 75.54% of
the voters. The related Non-Binding Poll for BAL-005-1 reached quorum 82.53% of the
5
NERC, Consideration of Comments, Project 2010-14.2.1, (2015), available at
http://www.nerc.com/pa/Stand/Project%2020101421%20Phase%202%20DL/2010-14%202%201_Phase_2_BAL006-2_Survey_Consideration_of_Comments_11102015.pdf.
3
ballot pool, and the standard and associated documents received support from 74.38% of
the voters. The related Non-Binding Poll for FAC-001-3 reached quorum 82.53% of the
ballot pool, and the standard and associated documents received support from 75.44% of
the voters. During the comment period, there were 43 sets of responses, including
comments from approximately 117 different individuals and approximately 84
companies, representing 8 of the 10 industry segments. 6
F. Final Ballot
Proposed Reliability Standards BAL-005-1, BAL-006-3, and FAC-001-3 were
posted for a 10-final ballot period from January 29, 2016 through February 8, 2016. The
ballot for the proposed Reliability Standard BAL-005-1 and associated documents
reached quorum at 86.35% of the ballot pool, and the standard received sufficient
affirmative votes for approval, receiving support from 72.06% of the voters. The ballot
for proposed retirement of Reliability Standard BAL-006-2 reached quorum at 86.98% of
the ballot pool, and the retirement received sufficient affirmative votes for approval,
receiving support from 94.61% of the voters. The ballot for the proposed Reliability
Standard FAC-001-3 and associated documents reached quorum at 86.67% of the ballot
pool, and the standard received sufficient affirmative votes for approval, receiving
support from 80.15% of the voters. 7
G. Board of Trustees Adoption
Proposed Reliability Standards BAL-005-1, BAL-006-3, FAC-001-3, and all associated
documents were adopted by the NERC Board of Trustees on February 11, 2016.
6
NERC, Consideration of Comments, Project 2010-14.2.1, (Jan. 28, 2016), available at
http://www.nerc.com/pa/Stand/Project%2020101421%20Phase%202%20DL/2010-14.2.1_BAL-005-1_BAL-0062_FAC-001-3_C_of_C_01282016.pdf.
7
NERC, Standards Announcement, Project 2010-14.2.1 (Feb. 2016), available at
http://www.nerc.com/pa/Stand/Project%2020101421%20Phase%202%20DL/2010-14.2.1_BAL-005_006_FAC001_FB_Results_Word_Announce_02162016.pdf.
4
Complete Record of Development History
FAC-001-3 (81)
FAC-001-3
Clean (35) | Redline to Last Posted (36)
BAL-005-1
Clean (33) | Redline to Last Posted (34)
Draft 2
White Paper (82)
The ballots and non-binding
poll for this posting are
additional (even though
the system shows them as
initial). The standards were
previously balloted together
Additional Ballots and
Non-binding Polls
Vote
BAL-005-1
Clean (77) | Redline to Last Posted (78)
BAL-006-2
Clean (79) | Redline to Last Posted (80)
Info (83)
Final Ballots
Actions
Implementation Plans
FAC-001-3
Clean (74) | Redline to Last Posted (75)
Redline to Last Approved (76)
BAL-005-1
Clean (71) | Redline to Last Posted (72)
Redline to Last Approved (73)
Final Draft
Draft
12/31/15 - 01/11/16
01/29/16 - 02/08/16
Dates
BAL-006-2 (67)
BAL-005-1 (66)
Ballot Results
Summary (65)
FAC-001-3 (87)
BAL-006-2 (86)
BAL-005-1 (85)
Ballot Results
Summary (84)
Results
Consideration of
Comments
Purpose/Industry Need
The objective of BAL-005 is to establish requirements for acquiring necessary data for the Balancing Authority to calculate Reporting ACE so that balancing of resources and demand can be achieved under Tie-Line Bias Control. The current objective of BAL-006 is
to define a process for monitoring Balancing Authorities to ensure that, over the long term, Balancing Authority Areas do not excessively depend on other Balancing Authority Areas in the Interconnection for meeting their demand or Interchange obligations. As
the revisions proposed for BAL-006 focus on the minimum requirements for Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual Interchange between them, which reinforces that errors in coordination or process will be
identified.
Standard(s) Affected: BAL-005-0.2b - Automatic Generation Control, BAL-006-2 - Inadvertent Interchange, FAC-001-1 - Facility Connection Requirements
The NERC Standards Committee appointed ten industry subject matter experts to serve on the BARC 2 standard drafting team (BARC 2 SDT) in the fall of 2014.
As a result of that examination, the BARC 2 PRT recommended to REVISE BAL-005-0_2b and BAL-006-2.
Background
The NERC Standards Committee appointed eleven industry subject matter experts to serve on the BARC 2 periodic review team (BARC 2 PRT) in the fall of 2013. The BARC 2 PRT used background information on the standards and the questions set forth in the
Periodic Review Template developed by NERC and approved by the Standards Committee, along with associated worksheets and reference documents, to determine whether BAL-005-0_2b and BAL-006-2 should be: (1) affirmed as is (i.e., no changes needed);
(2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn.
Status
Final ballots for BAL-005-1 – Balancing Authority Control, FAC-001-3 – Facility Interconnection Requirements, and the recommended retirement of BAL-006-2 – Inadvertent Interchange concluded 8 p.m. Eastern, Monday, February 8,
2016. The voting results can be accessed via the links below. The standards will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Related Files | 2007-05 - Balancing Authority Controls | 2007-18 - Reliability-based Control | 2010-14.2 - Periodic Review of BAL Standards
Project 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls – BAL-005, BAL-006, FAC-001
Program Areas & Departments > Standards > Project 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls – BAL-005, BAL-006, FAC-001
Comment Period
Info (60)
Submit Comments
Unofficial Comment Form (Word) (42)
Mapping Documents
BAL-005-1
Clean (43) | Redline to Last Posted (44)
Draft 1
BAL-006-2 Recommended Revisions
Clean (54) | Redline (55)
Unofficial Survey Form (Word) (53)
Supporting Materials
White Paper (52)
FAC-001-3
BAL-005-1
Draft RSAWs
White Paper (51)
FAC-001-3 (50)
VRF/VSL Justifications
BAL-005-1 (49)
FAC-001-3
Clean (47) | Redline to Last Posted (48)
Updated Info (24)
Initial Ballot and Non-binding
Poll
Submit Responses
Info (56)
Survey Period
[email protected]
Send RSAW feedback to:
Info (59)
Vote
BAL-006-2
Clean (45) | Redline to Last Posted (46)
Info (64)
FAC-001-3 (41)
Updated Info (63)
Note: A non-binding poll will
not be conducted for BAL006-2 due to its
recommended retirement.
and are now balloting
separately.
Supporting Materials
BAL-006-2
Clean (39) | Redline to Last Posted (40)
BAL-005-1
Clean (37) | Redline to Last Posted (38)
Implementation Plans
09/04/15 - 09/14/15
09/16/15 - 09/25/15
11/24/15 - 01/11/16
11/10/15 - 01/11/16
Ballot Results (29)
Summary (28)
Comments
Received (57)
Comments
Received (61)
FAC-001-3 (70)
BAL-005-1 (69)
Non-binding Poll
Results
FAC-001-3 (68)
Consideration of
Comments (58)
Consideration of
Comments (62)
Submit Comments
[email protected]
Send RSAW feedback to:
Info (27)
BAL-005 and BAL-006
Clean (2) / Redline to Last Posted (3)
SAR
Final Standard Authorization Request (SAR) (1)
Submit Comments
Info (7)
Comment Period
Project 2010-14.2 Periodic Review of BAL Standards Reference Material
FAC-001-3
BAL-005-1
Draft RSAWs
White Paper (23)
(New)
FAC-001-3 (22)
(Updated)
BAL-006-3 (21)
BAL-005-1 (20)
Mapping Documents
Unofficial Comment Form (Word) (19)
Supporting Materials
FAC-001-3 (18)
BAL-006-3 (17)
Join Ballot Pools
Implementation Plans
BAL-005-1 (16)
Info (26)
Vote
Comment Period
Info (25)
FAC-001-3
Clean (14) | Redline to Last Approved (15)
BAL-006-3
Clean (12) | Redline to Last Approved (13)
BAL-005-1 (11)
07/16/14 - 08/14/14
08/14/15 - 09/14/15
07/30/15 - 08/28/15
07/30/15 - 09/14/15
Comments Received
(9)
Comments
Received (31)
Non-binding Poll
Results (30)
Consideration of
Comments (10)
Consideration of
Comments (32)
Supporting Documents
Unofficial Nomination Form (Word) (6)
Recommendation to Revise BAL-005 and BAL-006 (5)
Unofficial Comment Form (Word) (4)
Submit Nominations
Info (8)
Nomination Period
07/16/14 - 07/30/14
Standards Authorization Request Form
NERC welcomes suggestions to improve the
reliability of the Bulk-Power System through
[email protected].
improved Reliability Standards. Please use this
Standard Authorization Request (SAR) form to submit your request to propose a new Reliability
Standard, a revision to a Reliability Standard, or the retirement of a Reliability Standard.
When completed, please email this form to:
Request to propose a new Reliability Standard, a revision to a Reliability Standard, or the
retirement of a Reliability Standard
Title of Proposed Reliability
Standard:
BAL-005-3 – Automatic Generation Control and BAL-006-3 – Inadvertent
Interchange
Date Submitted:
February 18, 2014
SAR Requester Information
Name:
Doug Hils
Organization:
Duke Energy
Telephone:
513.287.2149
Email:
[email protected]
SAR Type (Check as many as applicable)
New Reliability Standard
Retirement of existing Reliability Standard
Revision to existing Reliability Standards
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The North American Electric Reliability Corporation (NERC) is required to conduct a periodic review of
each NERC Reliability Standard at least once every ten years, or once every five years for Reliability
Standards approved by the American National Standards Institute as an American National Standard.
Project 2010-14.2 - Phase 2 of Balancing Authority Reliability-based Controls (BARC 2) was included in
the current cycle of periodic reviews.
Standards Authorization Request Form
SAR Information
The NERC Standards Committee appointed eleven industry subject matter experts to serve on the BARC
2 periodic review team (BARC 2 PRT) in the fall of 2013. The BARC 2 PRT used background information
on the standards and the questions set forth in the Periodic Review Template developed by NERC and
approved by the Standards Committee, along with associated worksheets and reference documents, to
determine whether BAL-005-0_2b and BAL-006-2 should be: (1) affirmed as is (i.e., no changes needed);
(2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn.
As a result of that examination, the BARC 2 PRT recommends to REVISE BAL-005-0_2b and BAL-006-2,
and has therefore developed this Standard Authorization Request (SAR) outlining the proposed scope
and technical justification for the revisions.
Purpose or Goal (How does this request propose to address the problem described above?):
This SAR proposes revising BAL-005 and BAL-006 in line with the recommendations of the BARC 2 PRT
as described in the PRT Recommendation to Revise BAL-005 and BAL-006, (Attachment 1). The
proposed changes to the standards add clarity, remove redundancy, take into account technological
changes since the last versions of the standards, address FERC directives, and bring compliance
elements in accordance with NERC guidelines. A detailed description of the PRT’s recommended
changes are contained later in this SAR.
Identify the Objectives of the proposed Reliability Standard’s requirements (What specific reliability
deliverables are required to achieve the goal?):
The objective of BAL-005 is to establish requirements for acquiring necessary data for the Balancing
Authority to calculate Reporting ACE so that balancing of resources and demand can be achieved under
Tie-Line Bias Control. The current objective of BAL-006 is to define a process for monitoring Balancing
Authorities to ensure that, over the long term, Balancing Authority Areas do not excessively depend on
other Balancing Authority Areas in the Interconnection for meeting their demand or Interchange
obligations. As the revisions proposed for BAL-006 focus on the minimum requirements for Adjacent
Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual Interchange
between them, which reinforces that errors in coordination or process will be identified, the PRT
recommends that the SDT revise the Purpose statement to be consistent with the Requirements as
further developed under this SAR.
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SAR Information
Brief Description (Provide a paragraph that describes the scope of this Reliability Standard action.)
The scope of this standard action is to revise BAL-005 and BAL-006 in accordance with the
recommendations made by the PRT in the PRT Recommendation to Revise BAL-005 and BAL-006,
(Attachment 1), and consistent with industry consensus to make additional standard revisions to the
extent such consensus develops.
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 Reliability Standard, including an assessment of the reliability and market interface impacts of
implementing or not implementing the Reliability Standard action.)
1. BAL-005
The BARC2 PRT has completed its review of BAL-005, and, among other recommendations, proposes
certain revisions below which would remove references to the types of resources and reserves utilized
by the Balancing Authority to balance resources and demand. The PRT recommendations focus on the
components that make up the Reporting ACE, and not on the ancillary service aspects of resource
control that drew criticism from the industry for being specific to generation when BAL-005 was
originally filed with the FERC. Among other recommendations, for the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules (all similar in that they utilize real-time data from an agreed-upon
common source between Adjacent BAs), the PRT recommends requirements which are focused on Realtime operating data. The PRT’s recommendations for BAL-005 are fully detailed below.
1) Title: The PRT recommends changing the title of BAL-005 to “Balancing Authority Control” to
remove the implication that BAL-005 pertains exclusively to generation, and better reflect the
focus on the BA acquiring necessary data to calculate Reporting ACE so that balancing of
resources and demand can be achieved under Tie-Line Bias Control. Based upon the input from
the industry, the PRT recommends that the SDT consider whether the term AGC should be
retained within any requirements. The PRT also recommends that the SDT pursue revisions to
the definition of AGC as proposed below to be resource-neutral.
AGC: Equipment that automatically adjusts generation resources utilized in a Balancing Authority Area from a
central location to maintain the Balancing Authority’s Reporting ACE within the bounds required under the
NERC Reliability Standards. Resources utilized under AGC may include conventional generation, variable
energy resources, storage devices and loads acting as resources, such as Demand Response. may interchange
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schedule plus Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction.
2) Purpose: The SDT would also be tasked with consideration of revising the “Purpose” statement
to focus on acquiring the information necessary for calculating Reporting ACE, while remaining
neutral on the types of reserves or resources utilized. The PRT recommends the following
revised Purpose statement for SDT consideration:
This standard establishes requirements for acquiring necessary data for the Balancing
Authority so that balancing of resources and demand can be achieved under Tie-Line Bias
Control.
Within the Purpose statement or Applicability section, the PRT also recommends that the SDT
consider addressing the Hydro Quebec exception for tie line bias control in some form, or a
single-BA exception.
3) Applicability: The SDT should remove “Generator Operators”, “Transmission Operators”, and
“Load Serving Entities” as applicable entities unless specificially added into a Standard
requirement by the SDT.
4) Requirement R1: The PRT recommends that the content of Requirement R1 be split between
what is needed for ensuring facilities are within a BA Area prior to MW being generated or
consumed, and what is needed for ensuring balanced operation within an Interconnection. First,
the PRT recommends that the SDT consider continuing discussions with the FAC SDT regarding
moving and restating or clarifying the TOP, LSE, and GOP requirements in a FAC Standard to
ensure facilities are within the metered boundaries of a BA prior to transmission operation,
resource operation, or load being served. The PRT discussed that the ownership of metering
and other factors may drive why the LSE is included in this standard, along with other entities;
however, consideration should be given to moving requirements for these facilities to be within
a BA Area into a FAC standard. The PRT is concerned that removing any such requirements of
the LSE, TOP, and GOP and not reflecting them within another standard may inadvertently
transfer certain obligations to the BA to ensure that such loads, resources, and facilities are
within the BA’s metered boundaries. The SDT should explore whether the role of the TOP would
appropriately cover the loads interconnected to that TOP, such that the LSE requirement may
not be necessary. Second, the PRT recommends that the SDT revise Requirements R1 and R2 to
be BA requirements that all Actual Net Interchange and Scheduled Net Interchange used by the
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BA in its Reporting ACE calculation also have an Adjacent BA, as proposed in the redlined
Requirements R1 and R2. Note that the PRT does not intend with the proposed language to
impose any additional requirements on the BA that currently apply to the LSE, GOP, and TOP,
but also believes that the requirements to identify the applicable BA should perhaps be in the
interconnection agreements (via FERC’s OATT or NAESB, for example) or a FAC requirement.
With respect to proposed R2, the SDT should ensure that the requirement cannot be
misinterpreted to imply that Dynamic Schedules can only be with physically adjacent BAs. The
intent is to address adjacency in a manner consistent with the scheduling path no differently
than used for interchange schedules.
5)
Requirement R2: Retirement approved by FERC effective January 21, 2014.
6) Requirement R3: The PRT recommends that the SDT not use the term “Regulation Service,” as in
general this statement could apply to implementation of Dynamic Schedules or Pseudo-Ties, and
the desire to have a common point for the data shared between the BAs implementing the
Dynamic Transfer. The PRT recommends removing “adequate” and “Burden” from the
requirement. The PRT recommends expanding Requirement R3 to be applicable to the
implementation of tie lines, Pseudo-Ties, and Dynamic Schedules, as all require agreement
between adjacent BAs on the agreed-upon points to be implemented. The PRT recommends
that the SDT review the other standards such as TOP-005 to assure there is no duplication or
redundancy specific to the concern on swapping hourly values in BAL-005 posted for industry
comment. The PRT recommends deleting the proposed R3.2 and the first sentence of the
proposed R3.5.2. The PRT also recommends the SDT develop a guideline document to
accompany BAL-005 covering some of the suggested best practices.
7) Requirement R4: The PRT reviewed Requirement R4 with respect to what notification or
coordination is necessary that could be considered with the other requirements in this Standard
regarding Interchange. Initially the PRT was considering a recommendation that the SDT
consider the requirement as it applies to Dynamic Transfer implementation as discussed in the
Dynamic Transfer reliability guideline, and as it applies to the practice of implementing multipleBA Dynamic Transfers under a process referred to as ACE Diversity Interchange. The PRT also
considered recommendations to delete or modify Requirement R4 so that it requires
communication with not only the BAs, but any other affected entities, and also to strike
“providing Regulation Service.” However, after further review, the PRT recommends retiring
Requirement R4, as the basis for coordination of common values between adjacent BAs is
covered in Requirement R3, and correction of information not available has also been
addressed. These requirements should ensure that any failure to perform would be reflected in
the BA performance under BAL-001-2.
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8) Requirement R5: The PRT recommends retiring Requirement R5, as the requirements placed
upon the implementation of Dynamic Transfers are covered within Requirement R3. With
respect to having a backup plan to the extent that a service may no longer be provided, the PRT
believes this would be covered in the terms agreed to between the parties implementing the
Dynamic Transfer. As proposed by the PRT, the requirements remaining in BAL-005 would
ensure that any failure to perform would be reflected in the BA performance under BAL-001-2.
9) Requirement R6: The PRT recommends that the sentence “Single Balancing Authorities
operating asynchronously may employ alternative ACE calculations such as (but not limited to)
flat frequency control” be captured in the definition of “Reporting ACE.”. The terms used in
Requirement R6 need to be consistent with those used in Reporting ACE if the Requirement is
retained. The SDT should consider whether the 30-minute requirement for RC notification is
sufficient or excessive. The PRT recommends that if a timing requirement remains in the
standard that it be structured in a manner to not require communication with the RC if the
capability to calculate Reporting ACE is restored within the defined notification period.
10) Requirement R7: The PRT recommends retiring this Requirement under Paragraph 81. The first
sentence covers having a functional EMS or other system capable of calculating Reporting ACE
and controlling resources, which can be done manually without any detriment to reliability.
EOP-008-1 Requirement R1 recognizes that such automated capability may not be available for
up to two hours for loss of control center functionality. In addition, the second sentence is not
needed, as such actions would be covered under EOP-008. The PRT believes that the term
“Operating AGC” in Requirement R7 refers to the capability to continuously calculate ACE (not
automatic control of resources), which should be considered one of the BAs functional
obligations with regard to the reliable operations and situational awareness of the BES. Though
redundancy and other provisions may be in place to maintain EMS functionality, there are times
when the information may not be available where the provisions under EOP-008-1 would apply.
11) Requirement R8: The PRT recommends that the SDT revise the Requirement with the proper
context of a minimum normal scan rate and clarify how frequently all components must be
factored into the Reporting ACE equation under normal operation. With respect to the subrequirements, the SDT should ensure that any proposed revisions accommodate abnormal and
emergency operations, including the possibility that the EMS or supporting telemetry may not
be available, such as during an evacuation to a backup site. The PRT notes that the SDT should
consider a requirement focused on a minimum scan-rate expectation under normal operations,
rather than a requirement that could be interpreted as if systems have 100% availability.
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12) Requirement R8, Part 8.1: The BA should have visibility of system frequency within parameters
consistent with EOP-008, however the PRT recommends that the requirement not be
prescriptive. The SDT should review EOP-008 to ensure that this requirement is covered there.
In addition, the SDT should also consider remote and redundant frequency resources to the
extent that the information that is otherwise available to the BA may not be available upon loss
of control center functionality. Such capability may already be anticipated under EOP-008. The
SDT should consider the following questions in the development of the revised requirement:
a) How much time is allowed to pass if the redundancy is lost before it must be restored?
b) Does the PRT believe it is acceptable for the second and independent frequency device
to be one used by another Balancing Authority?
13) Requirement R9, Part 9.1: The PRT recommends retiring this Requirement. The Actual Net
Interchange and Scheduled Net Interchange values in the Reporting ACE calculation include
provisions for the Balancing Authority to include its high voltage direct (HVDC) link to another
asynchronous interconnection. By assuring the values are handled consistently in the actual and
scheduled Interchange terms included in the real-time Reporting ACE by definition, the
Balancing Authority is not being instructed “how” to implement the HVDC link, but allowed to
decide the method it will use. By focusing on real-time Reporting ACE, we are assuring reliability
is addressed and maintained at all times.
14) Requirement R10 and R11: The PRT recommends retiring these requirements, as the basics of
both requirements are factored into the definition of Scheduled Net Interchange used in the
Reporting ACE calculation as defined in the NERC Glossary.
The PRT noted that Requirement R10 is written as if “Net Scheduled Interchange” is the value
used in the ACE equation; however, Net Scheduled Interchange has two meanings – the
algebraic sum of all Interchange Schedules across a given path, or between Balancing Authorities
for a given period or instant in time. Aside from the concern of having a definition with two
different meanings, the PRT believes that neither choice in the definition accurately depicts the
value inserted into the ACE or Reporting ACE, which would be the algebraic sum of all Net
Scheduled Interchange with all Adjacent Balancing Authorities, including Dynamic Schedules. In
addition, the PRT could not find a definition of Scheduled Interchange as used in Requirement
R11. Under Section 3 below, the PRT recommends changes to certain NERC definitions.
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15) Requirement R12: The PRT took a holistic approach to Requirement R12 and other requirements
related to the implementation of Tie-Lines, Pseudo-Ties, and Dynamic Schedules, as all relate to
the information exchanged between adjacent BAs.
The PRT recommends a new Requirement R3 related to the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, where each respective Adjacent BA has agreed to common
measuring points that produce an agreed-to value to be included in the calculation of Reporting
ACE. The SDT should review the requirement as it relates to current practices to ensure the
reliability needs are met.
The PRT suggests that the holistic approach shall only be achieved if there is a comprehensive
definition of ACE. Therefore, the PRT recommends the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to assure that they
are comprehensive (including items such as all AC Tie-Lines, Pseudo-ties, and all other necessary
Adjacent BA information). The PRT notes that the comprehensive details of the ACE calculation
in BAL-001-1 will be retired upon implementation of BAL-001-2, where ACE will only be defined
in the NERC Glossary. The PRT suggests that a complete review of all the NERC Standards for use
of the term “ACE” is necessary to assure that any update to the ACE definition would not impact
any other Standard.
16) Requirement R13: The PRT suggests deleting the first sentence of R13, and suggests that the
SDT include in a guideline document the practice of performing hourly error checks of the Actual
Net Interchange (NIA) operated to for the hour against an end-of-the-hour reference.
The PRT also recommends a separate requirement specific to adjustments as needed to the
Reporting ACE to reflect the meter error adjustment. However, the PRT is concerned that
requiring correction of a component of ACE when in error (no matter how negligible) would be
problematic in that not all errors require correction. The PRT recommends that the SDT consider
stating the requirement in such a manner that IME is required to be zero except during times
needed to compensate for any data or equipment error affecting a component of the Reporting
ACE calculation (interchange or frequency). When writing the requirement, the SDT should also
consider that there are other means of addressing metering corrections besides use of the IME
term, which may include possible revision to real-time metering data. Uses of the IME term in the
Reporting ACE may also be an appropriate subject for the guideline document the PRT is
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recommending that the SDT develop to accompany BAL-005 covering some of the suggested
best practices.
Requirement R14: The PRT recommends that the SDT delete the first sentence in R14 and revise
the second sentence to cover the minimum amount of information expected for the BA to
provide in real-time to its operator. The PRT also recommends that the individual components
of actual and scheduled interchange with each Adjacent Balancing Authority also be captured
(Tie-Lines, Pseudo-Ties, Dynamic Schedules, block schedules as needed for coordination, and
real-time schedules). Based on industry comments, the SDT should consider whether this
requirement is needed in the BAL standards, whether it is adequately covered elsewhere in the
standards, or whether it should be moved to the NERC Rules of Procedure for certification of the
Functional Entity.
17) Requirement R15: The SDT should consider placing a requirement in a FAC Standard with
respect to supporting infrastructure or functionality, or review EOP-008 to determine if existing
requirements adequately address primary control center functionality.
18) Requirement R16: The PRT recommends moving the requirement for flagging bad data to
revisions made in Requirement R14.
19) Requirement R17: The PRT recommends that this requirement be written to be specific to the
equipment used to determine the frequency component required for Reporting ACE. The PRT
also recommends that the SDT move any accuracy requirements applicable to the needs of the
Transmission Operator, (which may include MW, MVAR, voltage, potential transformer, current
transformer, and remote terminal unit or equivalent) to a TOP or FAC standard. Further study
would be needed on the “.25% of full scale” and the “appropriate accuracy” language.
2. BAL-006
The BARC2 PRT has completed its review of BAL-006 and recommends that it be revised. The
recommendations below include moving any requirements with implications for real-time operations
into BAL-005.
Among other work, the review team considered a FERC directive that recommended the development
of a metric to bound the magnitude of inadvertent accumulations, as those accumulations may be
indicative of a BA excessively leaning on the resources of others in its Interconnection. The review team
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consensus was that an Inadvertent Interchange accumulation value alone cannot yield useful
information concerning whether a BA is operating reliably. The PRT document on the consideration of
issues and directives more fully covers the PRT recommendations related to the FERC directives. The
PRT’s recommendations for BAL-006 are fully detailed below.
1) Purpose: As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be
identified, the PRT recommends that the SDT revise the Purpose statement to be consistent with
the Requirements as further developed under the SAR posted with this recommendation.
2) Requirement R1: The PRT recommends removing Requirement R1 as written and recommends
that the SDT determine if there is merit in developing a reliability metric specific to this standard
to measure performance to certain requirements under BAL-006, including the consideration of
including the calculation of Inadvertent Interchange. In development of any metric, the PRT
recommends that the SDT determine the appropriate time-frame for reliability (as close to realtime as possible). Similar to how BAL-001-2 has CPS1 and BAAL measures dependent upon the
BA calculating its Reporting ACE without a stated requirement that “Each BA shall calculate its
Reporting ACE”, the PRT felt that if the industry supports a measure being developed that uses
Inadvertent Interchange in the measure of performance, that the BA would calculate
Inadvertent Interchange as needed to comply. Also, similar to the approach taken for defining
Reporting ACE in the Glossary with all of the components necessary for the calculation, the PRT
is recommending in Requirement R2 below that the definition of Inadvertent Interchange also
be updated so that all components necessary for the calculation are identified.
3) Requirement R2: The PRT recommends incorporating Requirement R2 into a revised definition
of Inadvertent Interchange: The PRT recommends that this definition be modified to capture
that the calculation is on an hourly basis and includes the megawatt-hour values for Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, along with other scheduled interchange implemented
under block scheduling, which does not include the effect of the ramps. The PRT recommends
that the definition also include the NERC definitions of On-Peak Accounting and Off-Peak
Accounting, which reference the NAESB business practice for inadvertent interchange
accounting. The PRT also recommends that the definition clarify the treatment of scheduled and
actual interchange associated with asynchronous ties between Interconnections.
4) Requirement R3: The PRT recommends incorporating Requirement R3 into BAL-005, as the
requirement relates to the agreement on common values used in Real-time and also
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recommends developing a guideline to cover the practice of comparing the hourly megawatthour values gathered at the end of the hour against the hourly integrated values of the scan-rate
data operated to, in order to determine if significant error exists.
5) Requirement R4: The SDT should review current practices for confirmation of interchange afterthe-fact to determine and justify a shorter duration for agreement on such values for reliability
purposes. The PRT also recommends that Requirement R4 be restated to require that the
agreement is based upon the aggregate net schedules and net actuals by adjacent BAs as further
defined in the new definition of Inadvertent Interchange. In concept, every Tie-Line, Pseudo-Tie,
and Interchange Schedule (including Dynamic Schedules) implemented in the Reporting ACE
calculation should have an accompanying after-the-fact megawatt-hour value accounted for in
the calculation of Inadvertent Interchange.
6) Requirement R4, Part 4.2: The SDT should evaluate whether to retire this Requirement, as it is
addressed in the new definition of Inadvertent Interchange by the proposed reference to OnPeak Accounting and Off-Peak Accounting.
7) Requirement R4.3: The SDT should review this requirement to determine what elements of the
requirement are necessary to support reliability. The SDT also should consider including in a
guideline document a practice to support providing operations personnel with information on
the comparison of monthly revenue class meters to meters used for real-time operation.
8) Requirement R5: The SDT should review whether the practice that requires BAs to mutually
agree by the 15th calendar day is needed for reliability. The PRT believes there may be merit in
requiring BAs to identify the cause of the dispute, and to either correct it within a prescribed
number of days, or follow a dispute resolution process. The SDT should ensure that the
requirement is clear and distinct, which may require modifying or striking the language
regarding dispute resolution.
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Reliability Functions
The Reliability Standards will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
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Reliability Functions
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Reliability
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Reliability 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 Reliability Standard.
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Enter
(yes/no)
Yes.
Yes.
Yes.
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Reliability and Market Interface Principles
4. A Reliability Standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with Reliability Standards.
Yes.
Related Reliability Standards
Reliability
Standard No.
Explanation
BAL-001-2 and
draft BAL-002-2
Some of the proposed revisions to BAL-005 focus on the components used to
calculate Reporting ACE, used to measure compliance to CPS1 and BAAL in BAL001-2, and measure compliance in the draft BAL-002-2 revisions.
EOP-008-1
The purpose of EOP-008-1 is to ensure continued reliable operations of the Bulk
Electric System (BES) in the event that a control center becomes inoperable. For
certain proposed revisions to BAL-005 in this SAR, the PRT recommends that the
SDT consider provisions in EOP-008-1 for the loss of control center functionality.
FAC-001-1
With respect to BAL-005 Requirement R1, the PRT recommends that the SDT
consider moving and restating the TOP, LSE, and GOP requirements in an FAC
Standard to ensure facilities are within the metered boundaries of a BA prior to
transmission operation, resource operation, or load being served. The PRT
recommends that the SDT explore whether the role of the TOP would
appropriately cover the loads interconnected to that TOP, such that the LSE
requirement may not be necessary.
Other
The PRT recommendations include that the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to
assure that they are comprehensive (including items such as all AC Tie-Lines,
Pseudo-ties, and all other necessary Adjacent BA information). As the
comprehensive details of the ACE calculation in BAL-001-1 will be retired upon
implementation of BAL-001-2, where ACE will only be defined in the NERC
Glossary, the PRT suggests that a complete review of all the NERC Standards is
necessary to assure where ACE is utilized in a Standard, that any update to the ACE
definition would not impact any other Standard.
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Related SARs – N/A
SAR ID
Explanation
Regional Variances – N/A
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
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NERC welcomes suggestions to improve the
reliability of the Bulk-Power System through
[email protected].
improved Reliability Standards. Please use this
Standard Authorization Request (SAR) form to submit your request to propose a new Reliability
Standard, a revision to a Reliability Standard, or the retirement of a Reliability Standard.
When completed, please email this form to:
Request to propose a new Reliability Standard, a revision to a Reliability Standard, or the
retirement of a Reliability Standard
Title of Proposed Reliability
Standard:
BAL-005-3 – Automatic Generation Control and BAL-006-3 – Inadvertent
Interchange
Date Submitted:
February 18, 2014
SAR Requester Information
Name:
Doug Hils
Organization:
Duke Energy
Telephone:
513.287.2149
Email:
[email protected]
SAR Type (Check as many as applicable)
New Reliability Standard
Retirement of existing Reliability Standard
Revision to existing Reliability Standards
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The North American Electric Reliability Corporation (NERC) is required to conduct a periodic review of
each NERC Reliability Standard at least once every ten years, or once every five years for Reliability
Standards approved by the American National Standards Institute as an American National Standard.
Project 2010-14.2 - Phase 2 of Balancing Authority Reliability-based Controls (BARC 2) was included in
the current cycle of periodic reviews.
Standards Authorization Request Form
SAR Information
The NERC Standards Committee appointed eleven industry subject matter experts to serve on the BARC
2 periodic review team (BARC 2 PRT) in the fall of 2013. The BARC 2 PRT used background information
on the standards and the questions set forth in the Periodic Review Template developed by NERC and
approved by the Standards Committee, along with associated worksheets and reference documents, to
determine whether BAL-005-0_2b and BAL-006-2 should be: (1) affirmed as is (i.e., no changes needed);
(2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn.
As a result of that examination, the BARC 2 PRT recommends to REVISE BAL-005-0_2b and BAL-006-2,
and has therefore developed this Standard Authorization Request (SAR) outlining the proposed scope
and technical justification for the revisions.
Purpose or Goal (How does this request propose to address the problem described above?):
This SAR proposes revising BAL-005 and BAL-006 in line with the recommendations of the BARC 2 PRT
as described in the PRT Recommendation to Revise BAL-005 and BAL-006, (Attachment 1). The
proposed changes to the standards add clarity, remove redundancy, take into account technological
changes since the last versions of the standards, address FERC directives, and bring compliance
elements in accordance with NERC guidelines. A detailed description of the PRT’s recommended
changes are contained later in this SAR.
Identify the Objectives of the proposed Reliability Standard’s requirements (What specific reliability
deliverables are required to achieve the goal?):
The objective of BAL-005 is to establish requirements for acquiring necessary data for the Balancing
Authority to calculate Reporting ACE so that balancing of resources and demand can be achieved under
Tie-Line Bias Control. The current objective of BAL-006 is to define define a process for monitoring
Balancing Authorities to ensure that, over the long term, Balancing Authority Areas do not excessively
depend on other Balancing Authority Areas in the Interconnection for meeting their demand or
Interchange obligations. As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be identified,
the PRT recommends that the SDT revise the Purpose statement to be consistent with the
Requirements as further developed under this SAR.
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SAR Information
Brief Description (Provide a paragraph that describes the scope of this Reliability Standard action.)
The scope of this standard action is to revise BAL-005 and BAL-006 in accordance with the
recommendations made by the PRT in the PRT Recommendation to Revise BAL-005 and BAL-006,
(Attachment 1), and consistent with industry consensus to make additional standard revisions to the
extent such consensus develops.
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 Reliability Standard, including an assessment of the reliability and market interface impacts of
implementing or not implementing the Reliability Standard action.)
1. BAL-005
The BARC2 PRT has completed its review of BAL-005, and, among other recommendations, proposes
certain revisions below which would remove references to the types of resources and reserves utilized
by the Balancing Authority to balance resources and demand. The PRT recommendations focus on the
components that make up the Reporting ACE, and not on the ancillary service aspects of resource
control that drew criticism from the industry for being specific to generation when BAL-005 was
originally filed with the FERC. Among other recommendations, for the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules (all similar in that they utilize real-time data from an agreed-upon
common source between Adjacent BAs), the PRT recommends requirements focused on the real-time
values operated to. The PRT’s recommendations for BAL-005 are fully detailed below.
1) Title: The PRT recommends changing the title of BAL-005 to “Balancing Authority Control” to
remove the implication that BAL-005 pertains exclusively to generation, and better reflect the
focus on the BA acquiring necessary data to calculate Reporting ACE so that balancing of
resources and demand can be achieved under Tie-Line Bias Control. Based upon the input from
the industry, the PRT recommends that the SDT consider whether the term AGC should be
retained within any requirements. The PRT also recommends that the SDT pursue revisions to
the definition of AGC as proposed below to be resource-neutral.
AGC: Equipment that automatically adjusts generation resources utilized in a Balancing Authority Area from a
central location to maintain the Balancing Authority’s Reporting ACE within the bounds required under the
NERC Reliability Standards. Resources utilized under AGC may include conventional generation, variable
energy resources, storage devices and loads acting as resources, such as Demand Response. may interchange
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schedule plus Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction.
2) Purpose: The SDT would also be tasked with consideration of revising the “Purpose” statement
to focus on acquiring the information necessary for calculating Reporting ACE, while remaining
neutral on the types of reserves or resources utilized. The PRT recommends the following
revised Purpose statement for SDT consideration:
This standard establishes requirements for acquiring necessary data for the Balancing
Authority so that balancing of resources and demand can be achieved under Tie-Line Bias
Control.
Within the Purpose statement or Applicability section, the PRT also recommends that the SDT
consider addressing the Hydro Quebec exception for tie line bias control in some form, or a
single-BA exception.
3) Applicability: The SDT should remove “Generator Operators”, “Transmission Operators”, and
“Load Serving Entities” as applicable entities unless specificially added into a Standard
requirement by the SDT.
4) Requirement R1: The PRT recommends that the content of Requirement R1 be split between
what is needed for ensuring facilities are within a BA Area prior to MW being generated or
consumed, and what is needed for ensuring balanced operation within an Interconnection. First,
the PRT recommends that the SDT consider continuing discussions with the FAC SDT moving and
restating or clarifying the TOP, LSE, and GOP requirements in a FAC Standard to ensure facilities
are within the metered boundaries of a BA prior to transmission operation, resource operation,
or load being served. The PRT discussed that the ownership of metering and other factors may
drive why the LSE is included in this standard, along with other entities; however, consideration
should be given to moving requirements for these facilities to be within a BA Area into a FAC
standard. The PRT is concerned that removing any such requirements of the LSE, TOP, and GOP
and not reflecting them within another standard may inadvertently transfer certain obligations
to the BA to ensure that such loads, resources, and facilities are within the BA’s metered
boundaries. The SDT should explore whether the role of the TOP would appropriately cover the
loads interconnected to that TOP, such that the LSE requirement may not be necessary. Second,
the PRT recommends that the SDT revise Requirements R1 and R2 to be BA requirements that all
Actual Net Interchange and Scheduled Net Interchange used by the BA in its Reporting ACE
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calculation also have an Adjacent BA, as proposed in the redlined Requirements R1 and R2.
Note that the PRT does not intend with the proposed language to impose any additional
requirements on the BA that currently apply to the LSE, GOP, and TOP, but also believes that the
requirements to identify the applicable BA should perhaps be in the interconnection agreements
(via FERC’s OATT or NAESB, for example) or a FAC requirement. With respect to proposed R2,
the SDT should ensure that the requirement cannot be misinterpreted to imply that Dynamic
Schedules can only be with physically adjacent BAs. The intent is to address adjacency in a
manner consistent with the scheduling path no differently than used for interchange schedules.
5)
Requirement R2: Retirement approved by FERC effective January 21, 2014.
6) Requirement R3: The PRT recommends that the SDT not use the term “Regulation Service,” as in
general this statement could apply to implementation of Dynamic Schedules or Pseudo-Ties, and
the desire to have a common point for the data shared between the BAs implementing the
Dynamic Transfer. The PRT recommends removing “adequate” and “Burden” from the
requirement. The PRT recommends expanding Requirement R3 to be applicable to the
implementation of tie lines, Pseudo-Ties, and Dynamic Schedules, as all require agreement
between adjacent BAs on the agreed-upon points to be implemented. The PRT recommends
that the SDT review the other standards such as TOP-005 to assure there is no duplication or
redundancy. Specific to the concern on swapping hourly values in BAL-005 posted for industry
comment. The PRT recommends deleting the proposed R3.2 and the first sentence of the
proposed R3.5.2, the PRT also recommends the SDT develop a guideline document to
accompany BAL-005 covering some of the suggested best practices.
7) Requirement R4: The PRT reviewed Requirement R4 with respect to what notification or
coordination is necessary that could be considered with the other requirements in this Standard
regarding Interchange. Initially the PRT was considering a recommendation that the SDT
consider the requirement as it applies to Dynamic Transfer implementation as discussed in the
Dynamic Transfer reliability guideline, and as it applies to the practice of implementing multipleBA Dynamic Transfers under a process referred to as ACE Diversity Interchange. The PRT also
considered recommendations to delete or modify Requirement R4 so that it requires
communication with not only the BAs, but any other affected entities, and also to strike
“providing Regulation Service.” However, after further review, the PRT recommends retiring
Requirement R4, as the basis for coordination of common values between adjacent BAs is
covered in Requirement R3, and correction of information not available has also been
addressed. These requirements should ensure that any failure to perform would be reflected in
the BA performance under BAL-001-2.
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8) Requirement R5: The PRT recommends retiring Requirement R5, as the requirements placed
upon the implementation of Dynamic Transfers are covered within Requirement R3. With
respect to having a backup plan to the extent that a service may no longer be provided, the PRT
believes this would be covered in the terms agreed to between the parties implementing the
Dynamic Transfer. As proposed by the PRT, the requirements remaining in BAL-005 would
ensure that any failure to perform would be reflected in the BA performance under BAL-001-2.
9) Requirement R6: The PRT recommends that the sentence “Single Balancing Authorities
operating asynchronously may employ alternative ACE calculations such as (but not limited to)
flat frequency control” be captured in the definition of “Reporting ACE.”. The terms used in the
Requirement R6 need to be consistent with those used in Reporting ACE if the Requirement is
retained. The SDT should consider whether the 30-minute requirement for RC notification is
sufficient or excessive. The PRT recommends that if a timing requirement remains in the
standard that it be structured in a manner to not require communication with the RC if the
capability to calculate Reporting ACE is restored within the defined notification period.
10) Requirement R7: The PRT recommends retiring this Requirement under Paragraph 81. The first
sentence covers having a functional EMS or other system capable of calculating Reporting ACE
and controlling resources, which can be done manually without any detriment to reliability.
EOP-008-1 Requirement R1 recognizes that such automated capability may not be available for
up to two hours for loss of control center functionality. In addition, the second sentence is not
needed, as such actions would be covered under EOP-008. The PRT believes that the term
“Operating AGC” in Requirement R7 refers to the capability to continuously calculate ACE (not
automatic control of resources), which should be considered one of the BAs functional
obligations with regard to the reliable operations and situational awareness of the BES. Though
redundancy and other provisions may be in place to maintain EMS functionality, there are times
when the information may not be available where the provisions under EOP-008-1 would apply.
11) Requirement R8: The PRT recommends that the SDT revise the Requirement with the proper
context of a minimum normal scan rate and clarify how frequently all components must be
factored into the Reporting ACE equation under normal operation. With respect to the subrequirements, the SDT should ensure that any proposed revisions accommodate abnormal and
emergency operations, including the possibility that the EMS or supporting telemetry may not
be available, such as during an evacuation to a backup site. The PRT notes that the SDT should
consider a requirement focused on a minimum scan-rate expectation under normal operations,
rather than a requirement that could be interpreted as if systems have 100% availability.
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12) Requirement R8, Part 8.1: The BA should have visibility of system frequency within parameters
consistent with EOP-008, however the PRT recommends that the requirement not be
prescriptive. The SDT should review EOP-008 to ensure that this requirement is covered there.
In addition, the SDT should also consider remote and redundant frequency resources to the
extent that the information that is otherwise available to the BA may not be available upon loss
of control center functionality. Such capability may already be anticipated under EOP-008. The
SDT should consider the following questions in the development of the revised requirement:
a) How much time is allowed to pass if the redundancy is lost before it must be restored?
b) Does the PRT believe it is acceptable for the second and independent frequency device
to be one used by another Balancing Authority?
13) Requirement R9, Part 9.1: The PRT recommends retiring this Requirement. The Actual Net
Interchange and Scheduled Net Interchange values in the Reporting ACE calculation include
provisions for the Balancing Authority to include its high voltage direct (HVDC) link to another
asynchronous interconnection. By assuring the values are handled consistently in the actual and
scheduled Interchange terms included in the real-time Reporting ACE by definition, the
Balancing Authority is not being instructed “how” to implement the HVDC link, but allowed to
decide the method it will use. By focusing on real-time Reporting ACE, we are assuring reliability
is addressed and maintained at all times.
14) Requirement R10 and R11: The PRT recommends retiring these requirements, as the basics of
both requirements are factored into the definition of Scheduled Net Interchange used in the
Reporting ACE calculation as defined in the NERC Glossary.
The PRT noted that Requirement R10 is written as if “Net Scheduled Interchange” is the value
used in the ACE equation; however, Net Scheduled Interchange has two meanings – the
algebraic sum of all Interchange Schedules across a given path, or between Balancing Authorities
for a given period or instant in time. Aside from the concern of having a definition with two
different meanings, the PRT believes that neither choice in the definition accurately depicts the
value inserted into the ACE or Reporting ACE, which would be the algebraic sum of all Net
Scheduled Interchange with all Adjacent Balancing Authorities, including Dynamic Schedules. In
addition, the PRT could not find a definition of Scheduled Interchange as used in Requirement
R11. Under Section 3 below, the PRT recommends changes to certain NERC definitions.
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15) Requirement R12: The PRT took a holistic approach to Requirement R12 and other requirements
related to the implementation of Tie-Lines, Pseudo-Ties, and Dynamic Schedules, as all relate to
the information exchanged between adjacent BAs.
The PRT recommends a new Requirement R3 related to the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, where each respective Adjacent BA has agreed to common
measuring points that produce an agreed-to value to be included in the calculation of Reporting
ACE. The SDT should review the requirement as it relates to current practices to ensure the
reliability needs are met.
The PRT suggests that the holistic approach shall only be achieved if there is a comprehensive
definition of ACE. Therefore, the PRT recommends the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to assure that they
are comprehensive (including items such as all AC Tie-Lines, Pseudo-ties, and all other necessary
Adjacent BA information). The PRT notes that the comprehensive details of the ACE calculation
in BAL-001-1 will be retired upon implementation of BAL-001-2, where ACE will only be defined
in the NERC Glossary. The PRT suggests that a complete review of all the NERC Standards for use
of the term “ACE” is necessary to assure that any update to the ACE definition would not impact
any other Standard.
16) Requirement R13: The PRT suggests deleting the first sentence of R13, and suggests that the
SDT include in a guideline document the practice of performing hourly error checks of the Actual
Net Interchange (NI A) operated to for the hour against an end-of-the-hour reference.
The PRT also recommends a separate requirement specific to adjustments as needed to the
Reporting ACE to reflect the meter error adjustment. However, the PRT is concerned that
requiring correction of a component of ACE when in error (no matter how negligible) would be
problematic in that not all errors require correction. The PRT recommends that the SDT consider
stating the requirement in such a manner that I ME is required to be zero except during times
needed to compensate for any data or equipment error affecting a component of the Reporting
ACE calculation (interchange or frequency). When writing the requirement, the SDT should also
consider that there are other means of addressing metering corrections besides use of the I ME
term, which may include possible revision to real-time metering data. Uses of the I ME term in
the Reporting ACE may also be an appropriate subject for the guideline document the PRT is
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recommending that the SDT develop to accompany BAL-005 covering some of the suggested
best practices.
Requirement R14: The PRT recommends that the SDT delete the first sentence in R14 and revise
the second sentence to cover the minimum amount of information expected for the BA to
provide in real-time to its operator. The PRT also recommends that the individual components
of actual and scheduled interchange with each Adjacent Balancing Authority also be captured
(Tie-Lines, Pseudo-Ties, Dynamic Schedules, block schedules as needed for coordination, and
real-time schedules). Based on industry comments, the SDT should consider whether this
requirement is needed in the BAL standards, whether it is adequately covered elsewhere in the
standards, or whether it should be moved to the NERC Rules of Procedure for certification of the
Functional Entity.
17) Requirement R15: The SDT should consider placing a requirement in a FAC Standard with
respect to supporting infrastructure or functionality, or review EOP-008 to determine if existing
requirements adequately address primary control center functionality.
18) Requirement R16: The PRT recommends moving the requirement for flagging bad data to
revisions made in Requirement R14.
19) Requirement R17: The PRT recommends that this requirement be written to be specific to the
equipment used to determine the frequency component required for Reporting ACE. The PRT
also recommends that the SDT move any accuracy requirements applicable to the needs of the
Transmission Operator, (which may include MW, MVAR, voltage, potential transformer, current
transformer, and remote terminal unit or equivalent) to a TOP or FAC standard. Further study
would be needed on the “.25% of full scale” and the “appropriate accuracy” language.
2. BAL-006
The BARC2 PRT has completed its review of BAL-006 and recommends that it be revised. The
recommendations below include moving any requirements with implications for real-time operations
into BAL-005.
Among other work, the review team considered a FERC directive that recommended the development
of a metric to bound the magnitude of inadvertent accumulations, as those accumulations may be
indicative of a BA excessively leaning on the resources of others in its Interconnection. The review team
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consensus was that an Inadvertent Interchange accumulation value alone cannot yield useful
information concerning whether a BA is operating reliably. The PRT document on the consideration of
issues and directives more fully covers the PRT recommendations related to the FERC directives. The
PRT’s recommendations for BAL-006 are fully detailed below.
1) Purpose: As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be
identified, the PRT recommends that the SDT revise the Purpose statement to be consistent with
the Requirements as further developed under the SAR posted with this recommendation.
2) Requirement R1: The PRT recommends removing Requirement R1 as written and recommends
that the SDT determine if there is merit in developing a reliability metric specific to this standard
to measure performance to certain requirements under BAL-006, including the consideration of
including the calculation of Inadvertent Interchange. In development of any metric, the PRT
recommends that the SDT determine the appropriate time-frame for reliability (as close to realtime as possible). Similar to how BAL-001-2 has CPS1 and BAAL measures dependent upon the
BA calculating its Reporting ACE without a stated requirement that “Each BA shall calculate its
Reporting ACE”, the PRT felt that if the industry supports a measure being developed that uses
Inadvertent Interchange in the measure of performance, that the BA would calculate
Inadvertent Interchange as needed to comply. Also, similar to the approach taken for defining
Reporting ACE in the Glossary with all of the components necessary for the calculation, the PRT
is recommending in Requirement R2 below that the definition of Inadvertent Interchange also
be updated so that all components necessary for the calculation are identified.
3) Requirement R2: The PRT recommends incorporating Requirement R2 into a revised definition
of Inadvertent Interchange: The PRT recommends that this definition be modified to capture
that the calculation is on an hourly basis and includes the megawatt-hour values for Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, along with other scheduled interchange implemented
under block scheduling, which does not include the effect of the ramps. The PRT recommends
that the definition also include the NERC definitions of On-Peak Accounting and Off-Peak
Accounting, which reference the NAESB business practice for inadvertent interchange
accounting. The PRT also recommends that the definition clarify the treatment of scheduled and
actual interchange associated with asynchronous ties between Interconnections.
4) Requirement R3: The PRT recommends incorporating Requirement R3 into BAL-005, as the
requirement relates to the agreement on common values used in Real-time and also
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recommends developing a guideline to cover the practice of comparing the hourly megawatthour values gathered at the end of the hour against the hourly integrated values of the scan-rate
data operated to, in order to determine if significant error exists.
5) Requirement R4: The SDT should review current practices for confirmation of interchange afterthe-fact to determine and justify a shorter duration for agreement on such values for reliability
purposes. The PRT also recommends that Requirement R4 be restated to require that the
agreement is based upon the aggregate net schedules and net actuals by adjacent BAs as further
defined in the new definition of Inadvertent Interchange. In concept, every Tie-Line, Pseudo-Tie,
and Interchange Schedule (including Dynamic Schedules) implemented in the Reporting ACE
calculation should have an accompanying after-the-fact megawatt-hour value accounted for in
the calculation of Inadvertent Interchange.
6) Requirement R4, Part 4.2: The SDT should evaluate whether to retire this Requirement, as it is
addressed in the new definition of Inadvertent Interchange by the proposed reference to OnPeak Accounting and Off-Peak Accounting.
7) Requirement R4.3: The SDT should review this requirement to determine what elements of the
requirement are necessary to support reliability. The SDT also should consider including in a
guideline document a practice to support providing operations personnel with information on
the comparison of monthly revenue class meters to meters used for real-time operation.
8) Requirement R5: The SDT should review whether the practice that requires BAs to mutually
agree by the 15th calendar day is needed for reliability. The PRT believes there may be merit in
requiring BAs to identify the cause of the dispute, and to either correct it within a prescribed
number of days, or follow a dispute resolution process. The SDT should ensure that the
requirement is clear and distinct, which may require modifying or striking the language
regarding dispute resolution.
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Reliability Functions
The Reliability Standards will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
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Reliability Functions
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Reliability
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Reliability 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 Reliability Standard.
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Enter
(yes/no)
Yes.
Yes.
Yes.
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Reliability and Market Interface Principles
4. A Reliability Standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with Reliability Standards.
Yes.
Related Reliability Standards
Reliability
Standard No.
Explanation
BAL-001-2 and
draft BAL-002-2
Some of the proposed revisions to BAL-005 focus on the components used to
calculate Reporting ACE, used to measure compliance to CPS1 and BAAL in BAL001-2, and measure compliance in the draft BAL-002-2 revisions.
EOP-008-1
The purpose of EOP-008-1 is to ensure continued reliable operations of the Bulk
Electric System (BES) in the event that a control center becomes inoperable. For
certain proposed revisions to BAL-005 in this SAR, the PRT recommends that the
SDT consider provisions in EOP-008-1 for the loss of control center functionality.
FAC-001-1
With respect to BAL-005 Requirement R1, the PRT recommends that the SDT
consider moving and restating the TOP, LSE, and GOP requirements in an FAC
Standard to ensure facilities are within the metered boundaries of a BA prior to
transmission operation, resource operation, or load being served. The PRT
recommends that the SDT explore whether the role of the TOP would
appropriately cover the loads interconnected to that TOP, such that the LSE
requirement may not be necessary.
Other
The PRT recommendations include that the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to
assure that they are comprehensive (including items such as all AC Tie-Lines,
Pseudo-ties, and all other necessary Adjacent BA information). As the
comprehensive details of the ACE calculation in BAL-001-1 will be retired upon
implementation of BAL-001-2, where ACE will only be defined in the NERC
Glossary, the PRT suggests that a complete review of all the NERC Standards is
necessary to assure where ACE is utilized in a Standard, that any update to the ACE
definition would not impact any other Standard.
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Related SARs – N/A
SAR ID
Explanation
Regional Variances – N/A
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
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NERC welcomes suggestions to improve the
reliability of the Bulk-Power System through
[email protected].
improved Reliability Standards. Please use this
Standard Authorization Request (SAR) form to submit your request to propose a new Reliability
Standard, a revision to a Reliability Standard, or the retirement of a Reliability Standard.
When completed, please email this form to:
Request to propose a new Reliability Standard, a revision to a Reliability Standard, or the
retirement of a Reliability Standard
Title of Proposed Reliability
Standard:
BAL-005-3 – Automatic Generation Control and BAL-006-3 – Inadvertent
Interchange
Date Submitted:
February 18, 2014
SAR Requester Information
Name:
Doug Hils
Organization:
Duke Energy
Telephone:
513.287.2149
Email:
[email protected]
SAR Type (Check as many as applicable)
New Reliability Standard
Retirement of existing Reliability Standard
Revision to existing Reliability Standards
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The North American Electric Reliability Corporation (NERC) is required to conduct a periodic review of
each NERC Reliability Standard at least once every ten years, or once every five years for Reliability
Standards approved by the American National Standards Institute as an American National Standard.
Project 2010-14.2 - Phase 2 of Balancing Authority Reliability-based Controls (BARC 2) was included in
the current cycle of periodic reviews.
Standards Authorization Request Form
SAR Information
The NERC Standards Committee appointed eleven industry subject matter experts to serve on the BARC
2 periodic review team (BARC 2 PRT) in the fall of 2013. The BARC 2 PRT used background information
on the standards and the questions set forth in the Periodic Review Template developed by NERC and
approved by the Standards Committee, along with associated worksheets and reference documents, to
determine whether BAL-005-0_2b and BAL-006-2 should be: (1) affirmed as is (i.e., no changes needed);
(2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn.
As a result of that examination, the BARC 2 PRT recommends to REVISE BAL-005-0_2b and BAL-006-2,
and has therefore developed this Standard Authorization Request (SAR) outlining the proposed scope
and technical justification for the revisions.
Purpose or Goal (How does this request propose to address the problem described above?):
This SAR proposes revising BAL-005 and BAL-006 in line with the recommendations of the BARC 2 PRT
as described in the PRT Recommendation to Revise BAL-005 and BAL-006, (Attachment 1). The
proposed changes to the standards add clarity, remove redundancy, take into account technological
changes since the last versions of the standards, address FERC directives, and bring compliance
elements in accordance with NERC guidelines. A detailed description of the PRT’s recommended
changes are contained later in this SAR.
Identify the Objectives of the proposed Reliability Standard’s requirements (What specific reliability
deliverables are required to achieve the goal?):
The objective of BAL-005 is to establish requirements for acquiring necessary data for the Balancing
Authority to calculate Reporting ACE so that balancing of resources and demand can be achieved under
Tie-Line Bias Control. The current objective of BAL-006 is to define define a process for monitoring
Balancing Authorities to ensure that, over the long term, Balancing Authority Areas do not excessively
depend on other Balancing Authority Areas in the Interconnection for meeting their demand or
Interchange obligations. As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be identified,
the PRT recommends that the SDT revise the Purpose statement to be consistent with the
Requirements as further developed under this SAR.
Revised (11/28/2011)
2
Deleted: once the current 45-day industry comment
period concludes
Deleted: Also included on this posting is the Periodic
Review Recommendation to Revise BAL-005-0_2b –
Automatic Generation Control and BAL-006-2 – Inadvertent
Interchange, and redlined BAL-005 and BAL-006 as possible
illustrations of implementing the PRT’s recommendations.
One important purpose of all documents contained in this
posting is to elicit feeback from industry on the BARC 2
PRT’s recommendations.
Standards Authorization Request Form
SAR Information
Brief Description (Provide a paragraph that describes the scope of this Reliability Standard action.)
The scope of this standard action is to revise BAL-005 and BAL-006 in accordance with the
recommendations made by the PRT in the PRT Recommendation to Revise BAL-005 and BAL-006,
(Attachment 1), and consistent with industry consensus to make additional standard revisions to the
extent such consensus develops.
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 Reliability Standard, including an assessment of the reliability and market interface impacts of
implementing or not implementing the Reliability Standard action.)
1. BAL-005
The BARC2 PRT has completed its review of BAL-005, and, among other recommendations, proposes
certain revisions below which would remove references to the types of resources and reserves utilized
by the Balancing Authority to balance resources and demand. The PRT recommendations focus on the
components that make up the Reporting ACE, and not on the ancillary service aspects of resource
control that drew criticism from the industry for being specific to generation when BAL-005 was
originally filed with the FERC. Among other recommendations, for the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules (all similar in that they utilize real-time data from an agreed-upon
common source between Adjacent BAs), the PRT recommends requirements focused on the real-time
values operated to. The PRT’s recommendations for BAL-005 are fully detailed below.
1) Title: The PRT recommends changing the title of BAL-005 to “Balancing Authority Control” to
remove the implication that BAL-005 pertains exclusively to generation, and better reflect the
focus on the BA acquiring necessary data to calculate Reporting ACE so that balancing of
resources and demand can be achieved under Tie-Line Bias Control. Based upon the input from
the industry, the PRT recommends that the SDT consider whether the term AGC should be
retained within any requirements. The PRT also recommends that the SDT pursue revisions to
the definition of AGC as proposed below to be resource-neutral.
AGC: Equipment that automatically adjusts generation resources utilized in a Balancing Authority Area from a
central location to maintain the Balancing Authority’s Reporting ACE within the bounds required under the
NERC Reliability Standards. Resources utilized under AGC may include conventional generation, variable
energy resources, storage devices and loads acting as resources, such as Demand Response. may interchange
Revised (11/28/2011)
3
Deleted: , the hourly megawatt-hour information gathered
after the hour, and the hourly checking of the hourlyintegrated data against that megawatt-hour information to
determine if substantive error exists requiring correction
Deleted: The PRT suggested revisions in the redlined
BAL-005 include the removal of any reference to AGC;
Deleted: b
Standards Authorization Request Form
SAR Information
schedule plus Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction.
2) Purpose: The SDT would also be tasked with consideration of revising the “Purpose” statement
to focus on acquiring the information necessary for calculating Reporting ACE, while remaining
neutral on the types of reserves or resources utilized. The PRT recommends the following
revised Purpose statement for SDT consideration:
This standard establishes requirements for acquiring necessary data for the Balancing
Authority so that balancing of resources and demand can be achieved under Tie-Line Bias
Control.
Within the Purpose statement or Applicability section, the PRT also recommends that the SDT
consider addressing the Hydro Quebec exception for tie line bias control in some form, or a
single-BA exception.
3) Applicability: The SDT should remove “Generator Operators”, “Transmission Operators”, and
“Load Serving Entities” as applicable entities unless specificially added into a Standard
requirement by the SDT.
4) Requirement R1: The PRT recommends that the content of Requirement R1 be split between
what is needed for ensuring facilities are within a BA Area prior to MW being generated or
consumed, and what is needed for ensuring balanced operation within an Interconnection. First,
the PRT recommends that the SDT consider continuing discussions with the FAC SDT moving and
restating or clarifying the TOP, LSE, and GOP requirements in a FAC Standard to ensure facilities
are within the metered boundaries of a BA prior to transmission operation, resource operation,
or load being served. The PRT discussed that the ownership of metering and other factors may
drive why the LSE is included in this standard, along with other entities; however, consideration
should be given to moving requirements for these facilities to be within a BA Area into a FAC
standard. The PRT is concerned that removing any such requirements of the LSE, TOP, and GOP
and not reflecting them within another standard may inadvertently transfer certain obligations
to the BA to ensure that such loads, resources, and facilities are within the BA’s metered
boundaries. The SDT should explore whether the role of the TOP would appropriately cover the
loads interconnected to that TOP, such that the LSE requirement may not be necessary. Second,
the PRT recommends that the SDT revise Requirements R1 and R2 to be BA requirements that all
Actual Net Interchange and Scheduled Net Interchange used by the BA in its Reporting ACE
Revised (11/28/2011)
4
Deleted: Standards Drafting Team (
Deleted: )
Deleted: implementing the SAR developed by the PRT
should
Deleted: This standard establishes requirements for
acquiring necessary data for the Balancing Authority to
calculate Reporting ACE so that balancing of resources
and demand can be achieved
Deleted: T
Deleted: The SDT should remove “Generator
Operators”, “Transmission Operators”, and “Load Serving
Entities” as applicable entities unless used in the SDT’s
suggested revisions of this standard
Deleted: For example, the PRT discussed that the
ownership of metering and other factors may drive why
the LSE is included in this standard, along with other
entities, however consideration should be given to
moving requirements for facilities to be within a BA Area
to an FAC standard.
Deleted: n
Standards Authorization Request Form
SAR Information
calculation also have an Adjacent BA, as proposed in the redlined Requirements R1 and R2.
Note that the PRT does not intend with the proposed language to impose any additional
requirements on the BA that currently apply to the LSE, GOP, and TOP, but also believes that the
requirements to identify the applicable BA should perhaps be in the interconnection agreements
(via FERC’s OATT or NAESB, for example) or a FAC requirement. With respect to proposed R2,
the SDT should ensure that the requirement cannot be misinterpreted to imply that Dynamic
Schedules can only be with physically adjacent BAs. The intent is to address adjacency in a
manner consistent with the scheduling path no differently than used for interchange schedules.
5)
Requirement R2: Retirement approved by FERC effective January 21, 2014.
6) Requirement R3: The PRT recommends that the SDT not use the term “Regulation Service,” as in
general this statement could apply to implementation of Dynamic Schedules or Pseudo-Ties, and
the desire to have a common point for the data shared between the BAs implementing the
Dynamic Transfer. The PRT recommends removing “adequate” and “Burden” from the
requirement. The PRT recommends expanding Requirement R3 to be applicable to the
implementation of tie lines, Pseudo-Ties, and Dynamic Schedules, as all require agreement
between adjacent BAs on the agreed-upon points to be implemented. The PRT recommends
that the SDT review the other standards such as TOP-005 to assure there is no duplication or
redundancy. Specific to the concern on swapping hourly values in BAL-005 posted for industry
comment. The PRT recommends deleting the proposed R3.2 and the first sentence of the
proposed R3.5.2, the PRT also recommends the SDT develop a guideline document to
accompany BAL-005 covering some of the suggested best practices.
7) Requirement R4: The PRT reviewed Requirement R4 with respect to what notification or
coordination is necessary that could be considered with the other requirements in this Standard
regarding Interchange. Initially the PRT was considering a recommendation that the SDT
consider the requirement as it applies to Dynamic Transfer implementation as discussed in the
Dynamic Transfer reliability guideline, and as it applies to the practice of implementing multipleBA Dynamic Transfers under a process referred to as ACE Diversity Interchange. The PRT also
considered recommendations to delete or modify Requirement R4 so that it requires
communication with not only the BAs, but any other affected entities, and also to strike
“providing Regulation Service.” However, after further review, the PRT recommends retiring
Requirement R4, as the basis for coordination of common values between adjacent BAs is
covered in Requirement R3, and correction of information not available has also been
addressed. These requirements should ensure that any failure to perform would be reflected in
the BA performance under BAL-001-2.
Revised (11/28/2011)
5
Deleted: ,
Deleted: n
Deleted: The PRT recommends that the SDT review this
requirement to ensure that it is appropriately worded so
that adjacency is clearly defined.
Deleted: . Entities must have a process in place to
always have common and agreed-upon information even
when primary facilities are not available
Deleted: around
Standards Authorization Request Form
SAR Information
8) Requirement R5: The PRT recommends retiring Requirement R5, as the requirements placed
upon the implementation of Dynamic Transfers are covered within Requirement R3. With
respect to having a backup plan to the extent that a service may no longer be provided, the PRT
believes this would be covered in the terms agreed to between the parties implementing the
Dynamic Transfer. As proposed by the PRT, the requirements remaining in BAL-005 would
ensure that any failure to perform would be reflected in the BA performance under BAL-001-2.
9) Requirement R6: The PRT recommends that the sentence “Single Balancing Authorities
operating asynchronously may employ alternative ACE calculations such as (but not limited to)
flat frequency control” be captured in the definition of “Reporting ACE.”. The terms used in the
Requirement R6 need to be consistent with those used in Reporting ACE if the Requirement is
retained. The SDT should consider whether the 30-minute requirement for RC notification is
sufficient or excessive. The PRT recommends that if a timing requirement remains in the
standard that it be structured in a manner to not require communication with the RC if the
capability to calculate Reporting ACE is restored within the defined notification period.
10) Requirement R7: The PRT recommends retiring this Requirement under Paragraph 81. The first
sentence covers having a functional EMS or other system capable of calculating Reporting ACE
and controlling resources, which can be done manually without any detriment to reliability.
EOP-008-1 Requirement R1 recognizes that such automated capability may not be available for
up to two hours for loss of control center functionality. In addition, the second sentence is not
needed, as such actions would be covered under EOP-008. The PRT believes that the term
“Operating AGC” in Requirement R7 refers to the capability to continuously calculate ACE (not
automatic control of resources), which should be considered one of the BAs functional
obligations with regard to the reliable operations and situational awareness of the BES. Though
redundancy and other provisions may be in place to maintain EMS functionality, there are times
when the information may not be available where the provisions under EOP-008-1 would apply.
11) Requirement R8: The PRT recommends that the SDT revise the Requirement with the proper
context of a minimum normal scan rate and clarify how frequently all components must be
factored into the Reporting ACE equation under normal operation. With respect to the subrequirements, the SDT should ensure that any proposed revisions accommodate abnormal and
emergency operations, including the possibility that the EMS or supporting telemetry may not
be available, such as during an evacuation to a backup site. The PRT notes that the SDT should
consider a requirement focused on a minimum scan-rate expectation under normal operations,
rather than a requirement that could be interpreted as if systems have 100% availability.
Revised (11/28/2011)
6
Deleted: of
Deleted: the business arrangement
Deleted: The SDT should explore whether covering the
loss of the ability to calculate Reporting ACE is more
appropriate in EOP-008
Deleted: , and whether communication under such
circumstances could be better addressed elsewhere in
the standards, including EOP-008
Standards Authorization Request Form
SAR Information
12) Requirement R8, Part 8.1: The BA should have visibility of system frequency within parameters
consistent with EOP-008, however the PRT recommends that the requirement not be
prescriptive. The SDT should review EOP-008 to ensure that this requirement is covered there.
In addition, the SDT should also consider remote and redundant frequency resources to the
extent that the information that is otherwise available to the BA may not be available upon loss
of control center functionality. Such capability may already be anticipated under EOP-008. The
SDT should consider the following questions in the development of the revised requirement:
Deleted: the intent of
Deleted: , and to ensure consistency among the
standards
a) How much time is allowed to pass if the redundancy is lost before it must be restored?
b) Does the PRT believe it is acceptable for the second and independent frequency device
to be one used by another Balancing Authority?
13) Requirement R9, Part 9.1: The PRT recommends retiring this Requirement. The Actual Net
Interchange and Scheduled Net Interchange values in the Reporting ACE calculation include
provisions for the Balancing Authority to include its high voltage direct (HVDC) link to another
asynchronous interconnection. By assuring the values are handled consistently in the actual and
scheduled Interchange terms included in the real-time Reporting ACE by definition, the
Balancing Authority is not being instructed “how” to implement the HVDC link, but allowed to
decide the method it will use. By focusing on real-time Reporting ACE, we are assuring reliability
is addressed and maintained at all times.
14) Requirement R10 and R11: The PRT recommends retiring these requirements, as the basics of
both requirements are factored into the definition of Scheduled Net Interchange used in the
Reporting ACE calculation as defined in the NERC Glossary.
The PRT noted that Requirement R10 is written as if “Net Scheduled Interchange” is the value
used in the ACE equation; however, Net Scheduled Interchange has two meanings – the
algebraic sum of all Interchange Schedules across a given path, or between Balancing Authorities
for a given period or instant in time. Aside from the concern of having a definition with two
different meanings, the PRT believes that neither choice in the definition accurately depicts the
value inserted into the ACE or Reporting ACE, which would be the algebraic sum of all Net
Scheduled Interchange with all Adjacent Balancing Authorities, including Dynamic Schedules. In
addition, the PRT could not find a definition of Scheduled Interchange as used in Requirement
R11. Under Section 3 below, the PRT recommends changes to certain NERC definitions.
Revised (11/28/2011)
7
Deleted: . The PRT suggests that the Balancing Authority
during an audit may be asked to provide evidence that its
HVDC link was included or was not included in Reporting
ACE under the provisions allowed by definition
Deleted: the retirement of
Deleted: (NIs)
Standards Authorization Request Form
SAR Information
15) Requirement R12: The PRT took a holistic approach to Requirement R12 and other requirements
related to the implementation of Tie-Lines, Pseudo-Ties, and Dynamic Schedules, as all relate to
the information exchanged between adjacent BAs.
The PRT recommends a new Requirement R3 related to the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, where each respective Adjacent BA has agreed to common
measuring points that produce an agreed-to value to be included in the calculation of Reporting
ACE. The SDT should review the requirement as it relates to current practices to ensure the
reliability needs are met.
The PRT suggests that the holistic approach shall only be achieved if there is a comprehensive
definition of ACE. Therefore, the PRT recommends the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to assure that they
are comprehensive (including items such as all AC Tie-Lines, Pseudo-ties, and all other necessary
Adjacent BA information). The PRT notes that the comprehensive details of the ACE calculation
in BAL-001-1 will be retired upon implementation of BAL-001-2, where ACE will only be defined
in the NERC Glossary. The PRT suggests that a complete review of all the NERC Standards for use
of the term “ACE” is necessary to assure that any update to the ACE definition would not impact
any other Standard.
16) Requirement R13: The PRT suggests deleting the first sentence of R13, and suggests that the
SDT include in a guideline document the practice of performing hourly error checks of the Actual
Net Interchange (NI A) operated to for the hour against an end-of-the-hour reference.
The PRT also recommends a separate requirement specific to adjustments as needed to the
Reporting ACE to reflect the meter error adjustment. However, the PRT is concerned that
requiring correction of a component of ACE when in error (no matter how negligible) would be
problematic in that not all errors require correction. The PRT recommends that the SDT consider
stating the requirement in such a manner that I ME is required to be zero except during times
needed to compensate for any data or equipment error affecting a component of the Reporting
ACE calculation (interchange or frequency). When writing the requirement, the SDT should also
consider that there are other means of addressing metering corrections besides use of the I ME
term, which may include possible revision to real-time metering data. Uses of the I ME term in
the Reporting ACE may also be an appropriate subject for the guideline document the PRT is
Revised (11/28/2011)
8
Deleted: for common information similar to the
approach EOP-008-1 has taken with respect to describing
the manner in which the BA continues to meets its
functional obligations with regard to the reliable
operations of the BES
Deleted: re
Deleted: alancing Authority
Deleted: common
Deleted: . Accuracy and review of the agreed-to
common value is reflected in the new requirement
requiring comparison of hourly megawatt-hour values
against the integrated data operated to for Tie-Lines,
Dynamic Schedules, and Pseudo-Ties
Deleted: As
Deleted: , t
Deleted: where ACE is utilized in a Standard,
Deleted: .¶
¶
Similar to EOP-008-1, a holistic approach on common
information and agreed to common value would
eliminate duplication and potential for double jeopardy.
Deleted: moving elements of R13 as reflected on the
attached suggested redline. Specifically, for
Deleted: the PRT has suggested a redline change to
address performing
Formatted: Subscript
Standards Authorization Request Form
SAR Information
recommending that the SDT develop to accompany BAL-005 covering some of the suggested
best practices.
Requirement R14: The PRT recommends that the SDT delete the first sentence in R14 and revise
the second sentence to cover the minimum amount of information expected for the BA to
provide in real-time to its operator. The PRT also recommends that the individual components
of actual and scheduled interchange with each Adjacent Balancing Authority also be captured
(Tie-Lines, Pseudo-Ties, Dynamic Schedules, block schedules as needed for coordination, and
real-time schedules). Based on industry comments, the SDT should consider whether this
requirement is needed in the BAL standards, whether it is adequately covered elsewhere in the
standards, or whether it should be moved to the NERC Rules of Procedure for certification of the
Functional Entity.
17) Requirement R15: The SDT should consider placing a requirement in a FAC Standard with
respect to supporting infrastructure or functionality, or review EOP-008 to determine if existing
requirements adequately address primary control center functionality.
18) Requirement R16: The PRT recommends moving the requirement for flagging bad data to
revisions made in Requirement R14.
19) Requirement R17: The PRT recommends that this requirement be written to be specific to the
equipment used to determine the frequency component required for Reporting ACE. The PRT
also recommends that the SDT move any accuracy requirements applicable to the needs of the
Transmission Operator, (which may include MW, MVAR, voltage, potential transformer, current
transformer, and remote terminal unit or equivalent) to a TOP or FAC standard. Further study
would be needed on the “.25% of full scale” and the “appropriate accuracy” language.
2. BAL-006
The BARC2 PRT has completed its review of BAL-006 and recommends that it be revised. The
recommendations below include moving any requirements with implications for real-time operations
into BAL-005.
Among other work, the review team considered a FERC directive that recommended the development
of a metric to bound the magnitude of inadvertent accumulations, as those accumulations may be
indicative of a BA excessively leaning on the resources of others in its Interconnection. The review team
Revised (11/28/2011)
9
Deleted: made the recommendation reflected in the
proposed redline to define minimum expectations for
situational awareness of the BES
Deleted: ¶
Deleted: The PRT struggled with developing a
recommendation on this requirement, as one would
assume that the need to calculate Reporting ACE and the
expectation of the BA maintaining situational awareness
of the BES would not require a prescriptive requirement
for redundancy of power supply to ensure continuous
calculation of Reporting ACE and operation of vital data
acquisition and recording equipment. Conversely, should
the NERC requirements define the minimum expectations
for such functionality for a BA to demonstrate that it
meets the minimum expectations under EOP-008?
Deleted: additional requirements should be considered
for
Deleted: .
Deleted: elements
Deleted: . As such, the PRT recommends one
requirement to address the frequency device and a
separate requirement to address the MW measurement
Deleted: review whether any other accuracy
requirements that apply to the calculation of VARs and
voltage should be included in
Deleted: . The review team struggled with determining
whether much of the content of BAL-006 has a link to
reliability, or merely serves a bookkeeping function
Deleted: to
Deleted: Balancing Authority
Standards Authorization Request Form
SAR Information
consensus was that an Inadvertent Interchange accumulation value alone cannot yield useful
information concerning whether a BA is operating reliably. The PRT document on the consideration of
issues and directives more fully covers the PRT recommendations related to the FERC directives. The
PRT’s recommendations for BAL-006 are fully detailed below.
1) Purpose: As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be
identified, the PRT recommends that the SDT revise the Purpose statement to be consistent with
the Requirements as further developed under the SAR posted with this recommendation.
2) Requirement R1: The PRT recommends removing Requirement R1 as written and recommends
that the SDT determine if there is merit in developing a reliability metric specific to this standard
to measure performance to certain requirements under BAL-006, including the consideration of
including the calculation of Inadvertent Interchange. In development of any metric, the PRT
recommends that the SDT determine the appropriate time-frame for reliability (as close to realtime as possible). Similar to how BAL-001-2 has CPS1 and BAAL measures dependent upon the
BA calculating its Reporting ACE without a stated requirement that “Each BA shall calculate its
Reporting ACE”, the PRT felt that if the industry supports a measure being developed that uses
Inadvertent Interchange in the measure of performance, that the BA would calculate
Inadvertent Interchange as needed to comply. Also, similar to the approach taken for defining
Reporting ACE in the Glossary with all of the components necessary for the calculation, the PRT
is recommending in Requirement R2 below that the definition of Inadvertent Interchange also
be updated so that all components necessary for the calculation are identified.
Deleted: Balancing Authority
Deleted: . As the revisions proposed below focus on the
minimum requirements for Adjacent Balancing Authorities
to agree upon the hourly MW amounts of scheduled and
actual Interchange between them, which reinforces that
errors in coordination or process will be identified, the PRT
recommends that the SDT revise the Purpose statement to
be consistent with the requirements as further developed
under this SAR
Deleted: including the calculation of Inadvertent
Interchange in a reliability metric
Deleted: 5
3) Requirement R2: The PRT recommends incorporating Requirement R2 into a revised definition
of Inadvertent Interchange: The PRT recommends that this definition be modified to capture
that the calculation is on an hourly basis and includes the megawatt-hour values for Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, along with other scheduled interchange implemented
under block scheduling, which does not include the effect of the ramps. The PRT recommends
that the definition also include the NERC definitions of On-Peak Accounting and Off-Peak
Accounting, which reference the NAESB business practice for inadvertent interchange
accounting. The PRT also recommends that the definition clarify the treatment of scheduled and
actual interchange associated with asynchronous ties between Interconnections.
4) Requirement R3: The PRT recommends incorporating Requirement R3 into BAL-005, as the
requirement relates to the agreement on common values used in Real-time and also
Revised (11/28/2011)
Deleted: information
10
Standards Authorization Request Form
SAR Information
recommends developing a guideline to cover the practice of comparing the hourly megawatthour values gathered at the end of the hour against the hourly integrated values of the scan-rate
data operated to, in order to determine if significant error exists.
5) Requirement R4: The SDT should review current practices for confirmation of interchange afterthe-fact to determine and justify a shorter duration for agreement on such values for reliability
purposes. The PRT also recommends that Requirement R4 be restated to require that the
agreement is based upon the aggregate net schedules and net actuals by adjacent BAs as further
defined in the new definition of Inadvertent Interchange. In concept, every Tie-Line, Pseudo-Tie,
and Interchange Schedule (including Dynamic Schedules) implemented in the Reporting ACE
calculation should have an accompanying after-the-fact megawatt-hour value accounted for in
the calculation of Inadvertent Interchange.
Deleted: to determine if significant error exists between
Deleted: , and
Deleted: . The coordination and agreement of the
common points used for hourly megawatt-hour
accounting should be applicable to Tie-Lines, Pseudo-Ties
and Dynamic Schedules. A requirement for comparing
hourly megawatt-hour values to the hourly-integrated
values is reflected as well in the redlined suggested
revisions to BAL-005
Deleted: With respect to Requirement R4, the PRT
recommends that t
Deleted: for
Deleted: ,
6) Requirement R4, Part 4.2: The SDT should evaluate whether to retire this Requirement, as it is
addressed in the new definition of Inadvertent Interchange by the proposed reference to OnPeak Accounting and Off-Peak Accounting.
Deleted: r
7) Requirement R4.3: The SDT should review this requirement to determine what elements of the
requirement are necessary to support reliability. The SDT also should consider including in a
guideline document a practice to support providing operations personnel with information on
the comparison of monthly revenue class meters to meters used for real-time operation.
Deleted: PRT recommends that the
Deleted: investigate whether it can close the loop
Deleted: ensure
Deleted: that
8) Requirement R5: The SDT should review whether the practice that requires BAs to mutually
agree by the 15th calendar day is needed for reliability. The PRT believes there may be merit in
requiring BAs to identify the cause of the dispute, and to either correct it within a prescribed
number of days, or follow a dispute resolution process. The SDT should ensure that the
requirement is clear and distinct, which may require modifying or striking the language
regarding dispute resolution.
Revised (11/28/2011)
11
Deleted: are
Deleted: provided
Deleted: With respect to Requirement R5, the PRT
recommends that t
Deleted: require
Deleted: . The language as written may not be
sufficiently compulsory
Standards Authorization Request Form
Reliability Functions
The Reliability Standards will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.
Reliability Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Revised (11/28/2011)
12
Deleted: [;
Standards Authorization Request Form
Reliability Functions
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Reliability
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Reliability 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 Reliability Standard.
Revised (11/28/2011)
Enter
(yes/no)
Yes.
Yes.
Yes.
13
Standards Authorization Request Form
Reliability and Market Interface Principles
4. A Reliability Standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with Reliability Standards.
Yes.
Related Reliability Standards
Reliability
Standard No.
Explanation
BAL-001-2 and
draft BAL-002-2
Some of the proposed revisions to BAL-005 focus on the components used to
calculate Reporting ACE, used to measure compliance to CPS1 and BAAL in BAL001-2, and measure compliance in the draft BAL-002-2 revisions.
EOP-008-1
The purpose of EOP-008-1 is to ensure continued reliable operations of the Bulk
Electric System (BES) in the event that a control center becomes inoperable. For
certain proposed revisions to BAL-005 in this SAR, the PRT recommends that the
SDT consider provisions in EOP-008-1 for the loss of control center functionality.
FAC-001-1
With respect to BAL-005 Requirement R1, the PRT recommends that the SDT
consider moving and restating the TOP, LSE, and GOP requirements in an FAC
Standard to ensure facilities are within the metered boundaries of a BA prior to
transmission operation, resource operation, or load being served. The PRT
recommends that the SDT explore whether the role of the TOP would
appropriately cover the loads interconnected to that TOP, such that the LSE
requirement may not be necessary.
Other
The PRT recommendations include that the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to
assure that they are comprehensive (including items such as all AC Tie-Lines,
Pseudo-ties, and all other necessary Adjacent BA information). As the
comprehensive details of the ACE calculation in BAL-001-1 will be retired upon
implementation of BAL-001-2, where ACE will only be defined in the NERC
Glossary, the PRT suggests that a complete review of all the NERC Standards is
necessary to assure where ACE is utilized in a Standard, that any update to the ACE
definition would not impact any other Standard.
Revised (11/28/2011)
14
Standards Authorization Request Form
Related SARs – N/A
SAR ID
Explanation
Regional Variances – N/A
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
Revised (11/28/2011)
15
Unofficial Comment Form
Project 2010-14.2 Balancing Authority Reliability-based Control
Standard Authorization Request for BAL-005 and BAL-006
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standards Authorization Request (SAR). The electronic comment form must be
completed by 8:00 p.m. ET on August 14, 2014.
If you have questions please contact Darrel Richardson via email or by telephone at
[email protected] or 609-613-1848.
The project page may be accessed by clicking here.
Background Information
This posting is soliciting informal comment.
On September 19, 2013, the NERC Standards Committee appointed ten subject matter experts to serve on
the BARC 2 periodic review team (BARC 2 PRT). 1 As part of its review, the BARC 2 PRT used background
information on the standards and the questions set forth in the Periodic Review Template developed by
NERC and approved by the Standards Committee, along with associated worksheets and reference
documents, to determine whether BAL-005-0.2b and BAL-006-2 should be: (1) affirmed as is (i.e., no
changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3)
withdrawn.
The BARC 2 PRT recommendations for BAL-005-0.2b and BAL-006-2 were posted for a 45-day comment
period from February 21, 2014 through April 7, 2014. There were 23 sets of responses, including
comments from approximately 84 different people from approximately 62 companies, representing 8 of
the 10 Industry Segments.
The BARC 2 PRT carefully reviewed and considered the comments received during the posting period and,
based on stakeholder comments, made revisions to its recommendations. To support implementation of
these recommendations, the BARC 2 PRT developed a new SAR intended to supersede the original SAR,
which contains outdated information. To further support its recommendations, the BARC 2 PRT
developed redlined versions of the standards. Many improvements suggested by stakeholders during the
comment period were incorporated into the final recommendations and redlined standards being
provided.
1
The Standards Committee subsequently appointed an eleventh SME to the BARC 2 PRT.
The recommendations of the BARC 2 PRT are in the Periodic Review Templates and SAR. The redlined
standards are posted on the project page and will be included as part of the SAR for this project.
Additional documents developed to support the team’s recommendations have been posted on the
project page, including 1) the BARC 2 PRT’s consideration of comments on the draft recommendation; 2) a
list of directives and stakeholder-identified issues associated with the standards; and 3) the IERP
recommendations associated with the standards, containing the BARC 2 PRT’s consideration of those
recommendations.
This project addresses directives in Paragraphs 406 2, 415 3, 418 4, 419 5, 428 6 and 438 7 of FERC Order 693,
and provides additional clarity to many requirements, as well as retiring requirements that meet the
criteria developed in the Paragraph 81 project.
2
“Given that most of the commenters’ concerns over the inclusion of DSM as part of regulating reserves relate to the technical requirements, the Commission
clarifies that to qualify as regulating reserves, these resources must be technically capable of providing the service. In particular, all resources providing
regulation must be capable of automatically responding to real-time changes in load on an equivalent basis to the response of generation equipped with
automatic generation control. From the examples provided above, the Commission understands that it may be technically possible for DSM to meet equivalent
requirements as conventional generators and expects the Reliability Standards development process to provide the qualifications they must meet to
participate. These qualifications will be reviewed by the Commission when the revised Reliability Standard is submitted to the Commission for approval.”
3
“Both Xcel and FirstEnergy question Requirement R17 but do not oppose the Commission’s proposal to approve this Reliability Standard. Earlier in this Final
Rule, we direct the ERO to consider the comments received to the NOPR in its Reliability Standards development process. Thus, the comments of Xcel and
FirstEnergy should be addressed by the ERO when this Reliability Standard is revisited as part of the ERO’s Work Plan.”
4
“The Commission adopts the NOPR proposal to require the ERO to modifiy the Reliability Standards to include a Measure that provides for a verification
process over the minimum required automatic generation control or regulating reserves a balancing authority maintains.”
5 “FirstEnergy has a number of suggestions to improve the existing Reliability Standard and the ERO is directed to consider those suggestions in its Reliability
Standards development process.”
6 “The Commission directs the ERO to develop a modification to BAL-006-1 that adds Measures concerning the accumulation of large inadvertent imbalances
and Levels of Non-Compliance. . . [W]e are concerned that large imbalances represent dependence by some balancing authorities on their neighbors and are
an indication of less than desirable balancing of generation with load. The Commission also notes that the stated purpose of this Reliability Standard is to
define a process for monitoring balancing authorities to ensure that, over the long term, balancing authorities do not excessively depend on other balancing
authorities in the Interconnection for meeting their demand or interchange obligations.”
7 “Since the ERO indicates that the reliability aspects of this issue will be addressed in a Reliability Standards filing later this year, the Commission asks the ERO,
when filing the new Reliability Standard, to explain how the new Reliability Standard satisfies the Commission’s concerns.”
Unofficial Comment Form
Project 2010-14.2 BARC | July 2014
2
This posting is soliciting comment on a Standard Authorization Request (SAR).
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
Question
1. Do you have any specific questions or comments relating to the scope of the proposed SAR?
Yes
No
Comments:
2. If you are aware of the need for a regional variance or business practice that should be considered
with this phase of the project, please identify it here.
Yes
No
Comments:
3. Are you aware of any Canadian provincial or other regulatory requirements that may need to be
considered during this project in order to develop a continent-wide approach to the standard(s)? If
yes, please identify the jurisdiction and specific regulatory requirements.
Comments:
4. If you have any other comments on this SAR that you haven’t already mentioned, please provide
them here.
Comments:
Unofficial Comment Form
Project 2010-14.2 BARC | July 2014
3
Periodic Review of BAL-005-0.2b – Automatic
Generation Control and BAL-006-2 –
Inadvertent Interchange (Recommendation
to Revise both Standards)
May 22, 2014
Introduction
The North American Electric Reliability Corporation (NERC) is required to conduct a periodic review of
each NERC Reliability Standard at least once every ten years, or once every five years for Reliability
Standards approved by the American National Standards Institute as an American National Standard. 1
Project 2010-14.2 - Phase 2 of Balancing Authority Reliability-based Controls (BARC 2) was included in
the current cycle of periodic reviews.
The NERC Standards Committee appointed ten industry subject matter experts to serve on the BARC 2
periodic review team (BARC 2 PRT) on September 19, 2013.2 The BARC 2 PRT used background
information on the standards and the questions set forth in the Periodic Review Template developed
by NERC and approved by the Standards Committee, along with associated worksheets and reference
documents, to determine whether BAL-005-0_2b and BAL-006-2 should be: (1) affirmed as is (i.e., no
changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3)
withdrawn.
As a result of that examination, the BARC 2 PRT recommends to REVISE BAL-005-0_2b and BAL-006-2,
and has therefore developed a draft Standard Authorization Request (SAR) outlining the proposed
scope and technical justification for the revisions. The purpose of all documents contained in this
posting is to elicit feedback from industry on the BARC 2 PRT’s recommendations.
Applicable Reliability Standards: BAL-005-0.2b and BAL-006-2
Note: BAL-005-0 was filed for FERC approval on April 4, 2006 in Docket No. RM06-16000 and was approved on March 16, 2007 in Order No. 693.6. Also, FERC accepted an
errata filing to BAL-005-0.1b on September 13, 2012, which replaced Appendix 1 with a
corrected version of a FERC-approved interpretation, and made an internal reference
1
NERC Standard Processes Manual 45 (2013), posted at
http://www.nerc.com/pa/Stand/Documents/Appendix_3A_StandardsProcessesManual.pdf.
2
The Standards Committee subsequently appointed Scott Brooks of Manitoba Hydro to the BARC 2 PRT.
correction in the interpretation, thus resulting in BAL-005-0.2b. On March 16, 2007
FERC issued Order Number 693 approving Reliability Standard BAL-006-1. BAL-006-2,
which removed the MISO waivers found in BAL-006-1, was approved by FERC on January
6, 2011 in Docket No. RD10-04-000.
Team Members (include name and organization):
1. Doug Hils, Duke Energy (Chair)
2. Thomas W. (Tom) Siegrist, Brickfield Burchette Ritts and Stone, PC (Vice Chair)
3. Scott Brooks, Manitoba Hydro
4. Ron Carlsen, Southern Company
5. Howard F. Illian, Energy Mark, Inc.
6. Mike Potishnak, Representing NPCC
7. Jerry Rust, Northwest Power Pool
8. Robert Staton, Xcel Energy
9. Glenn Stephens, Santee Cooper
10. Stephen Swan, MISO
11. Mark Trumble, Omaha Public Power District
Date Review Completed: February 14, 2014
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
2
Background Information ( initially com pleted by NER C staff)
1. Are there any outstanding Federal Energy Regulatory Commission (FERC) directives associated with
the Reliability Standards? (If so, NERC staff will attach a list of the directives with citations to
associated FERC orders for inclusion in a SAR.)
Yes
No
Please see the attached Consideration of Issues and Directives.
2. Have stakeholders requested clarity on the Reliability Standards in the form of an Interpretation
(outstanding, in progress, or approved), Compliance Application Notice (CAN) (outstanding, in
progress, or approved), or an outstanding submission to NERC’s Issues Database? (If there are,
NERC staff will include a list of the Interpretation(s), CAN(s), or stakeholder-identified issue(s)
contained in the NERC Issues Database that apply to the Reliability Standard.)
Yes (See BAL-005-0.2b, Appendix 1 - Interpretation of Requirement R17)
No
3. Are the Reliability Standards one of the most violated Reliability Standards? If so, does the root
cause of the frequent violation appear to be a lack of clarity in the language?
Yes
No
Please explain:
4. Do the Reliability Standards need to be modified or converted to the results-based standard (RBS)
format as outlined in Attachment 1: Results-Based Standards? Note that this analysis is twofold and
requires collaboration among NERC staff and the Review Team. First, determine whether the
substance of the Reliability Standard comports to the RBS principles described in Attachment 1.
Second, ensure that, as Reliability Standards are reviewed, the formatting is changed as necessary
to comply with the current format of a Reliability Standard. If the answer to either part of this
question is “Yes,” the standard should be revised.
Yes
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
3
No
Note: The BARC 2 PRT reviewed BAL-005-0.2b and BAL-006-2 and determined that many of the
requirements were similar in nature and could be simplified to provide a clear and measurable
expected outcome, such as: (1) a stated level of reliability performance; (2) a reduction in a
specified reliability risk; or (3) a necessary competency.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
4
Additional Questions Considered by the BARC 2 PRT
If NERC staff answered “Yes” to any of the questions above, the Reliability Standard probably requires
revision. The questions below are intended to further guide your review. Some of the questions
reference documents provided by NERC staff as indicated in the Background questions above.
1. Paragraph 81: Does one or more of the requirements in the Reliability Standard meet criteria for
retirement or modification based on Paragraph 81 concepts? Use Attachment 2: Paragraph 81
Criteria to make this determination.
Yes
No
Please summarize your application of Paragraph 81 Criteria, if any: The BARC 2 PRT applied the
criteria specified in Attachment 2: Paragraph 81 Criteria in reviewing BAL-005 and BAL-006. As that
document more fully explains, for a Reliability Standard requirement to be proposed for retirement
or modification based on Paragraph 81 concepts, it must satisfy both an overarching criterion,
specifically, whether the requirement does little, if anything, to benefit or protect the reliable
operation of the Bulk Electric System (BES), and at least one other criterion specified therein. The
PRT concluded that eight requirements should be retired under Paragraph 81 concepts as detailed
in Table 1:
Table 1 - PRT Recommended Paragraph 81 Retirements
Requirement
BAL-005,
Requirement
R4
BAL-005,
Requirement
R5
BAL-005,
Requirement
R7
Rationale
The basis for coordination of common values between adjacent BAs is covered
in Requirement R3, and correction of information not available has also been
addressed. Therefore, this requirement is redundant and does little, if anything,
to benefit or protect the reliable operation of the BES.
The requirements placed upon the implementation of Dynamic Transfers are
covered within Requirement R3. Therefore, this requirement is redundant and
does little, if anything, to benefit or protect the reliable operation of the BES.
The first sentence covers having a functional EMS or other system capable of
calculating Reporting ACE and controlling resources, which can be done
manually without any detriment to reliability. EOP-008-1 Requirement R1
recognizes that such automated capability may not be available for up to two
hours for loss of control center functionality. In addition, the second sentence
is not needed, as such actions would be covered under EOP-008. The PRT
believes that the term “Operating AGC” in Requirement R7 refers to the
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
5
BAL-005,
Requirement
R9, Part 9.1
BAL-005,
Requirement
R10
BAL-005,
Requirement
R11
BAL-006,
Requirement
R1
BAL-006,
Requirement
R2
capability to continuously calculate ACE (not automatic control of resources),
which should be considered one of the BAs functional obligations with regard to
the reliable operations and situational awareness of the BES. Though
redundancy and other provisions may be in place to maintain EMS functionality,
there are times when the information may not be available where the provisions
under EOP-008-1 would apply. In light of these unnecessary redundancies, this
requirement does little, if anything, to benefit or protect the reliable operation
of the BES.
The Actual Net Interchange and Scheduled Net Interchange values in the
Reporting ACE calculation include provisions for the Balancing Authority to
include its high voltage direct (HVDC) link to another asynchronous
interconnection. By assuring the values are handled consistently in the actual
and scheduled Interchange terms included in the real-time Reporting ACE by
definition, the Balancing Authority is not being instructed “how” to implement
the HVDC link, but allowed to decide the method it will use. By focusing on realtime Reporting ACE, we are assuring reliability is addressed and maintained at all
times. Because the Reporting ACE addresses the reliability concerns originally
contemplated in this requirement, the requirement is needlessly redundant and
does little, if anything, to benefit or protect the reliable operation of the BES.
The definition of Reporting ACE includes the provision that Scheduled Net
Interchange (NIs) used in the Reporting ACE calculation include Dynamic
Schedules. Therefore, this requirement is redundant and does little, if anything,
to benefit or protect the reliable operation of the BES.
The definition of Reporting ACE includes the provision that the effect of
schedule ramps be included in the value Scheduled Net Interchange (NIs) used in
the Reporting ACE calculation. Therefore, this requirement is redundant and
does little, if anything, to benefit or protect the reliable operation of the BES.
Requirement R1 is written only as an energy accounting requirement. The
Requirement is administrative in nature and does little, if anything to benefit or
protect the reliable operation of the BES. However, the SDT should determine if
there is merit in developing a reliability metric specific to this standard including
the calculation of Inadvertent Interchange in a reliability metric to measure
performance to certain requirements under BAL-0065, where the SDT may
consider including the calculation of Inadvertent Interchange.
Requirement R2 is written only as an energy accounting requirement. The
Requirement is administrative in nature and does little, if anything to benefit or
protect the reliable operation of the BES. However, the PRT recommends that
the SDT incorporate Requirement R2 into a revised definition of Inadvertent
Interchange.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
6
The BARC 2 PRT carefully considered each recommendation made in the Independent Expert
Review Report (IERR) as detailed in Table 2 below. Based on the BARC 2 PRT’s discussions and
expertise on the matter, including some having been involved in the development and revisions to
NERC Policy 1 used as the basis for the NERC BAL Standards, the BARC 2 PRT determined that the
balance of the requirements recommended for retirement by the Independent Expert Review
Report are necessary to retain in some form for reliability:
Table 2 - PRT Consideration of IERR Recommendations
Requirement
BAL-005,
Requirement
R2
BAL-005,
Requirement
R3
IERR Recommendation
Retire, P81. Phase 1
PRT Response
Requirement removed under Paragraph 81 Phase 1.
Retire, P81. Duplicative
of R1.
The PRT disagreed with the IERR, as the intent of
Requirement R1 is to ensure that all load, resources
and transmission facilities are accounted for within
the BAs in an Interconnection, whereas Requirement
R3 was intended to cover the metering
communications, etc., when load or resources may
be Dynamically Transferred. The PRT
recommendations include treating the
implementation of Tie-Lines, Pseudo-Ties, and
Dynamic Schedules in a similar manner, as all require
agreement on the common information that will be
used between the Adjacent BAs and the
implementation of dynamically changing data in the
Reporting ACE. The PRT recommends that the SDT
not use the term “Regulation Service,” as in general
this statement could apply to implementation of
Dynamic Schedules or Pseudo-Ties, and the desire to
have a common point for the data shared between
the BAs implementing the Dynamic Transfer.
Entities must have a process in place to always have
common and agreed-upon information even when
primary facilities are not available. The PRT
recommends removing “adequate” and “Burden”
from the requirement.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
7
BAL-005,
Requirement
R8
Retire, P81. Outdated
due to technology.
BAL-005,
Requirement
R9
BAL-005,
Requirement
R10
Retire, P81. This is a
definition not a
requirement.
Retire, P81. This is a
definition not a
requirement.
BAL-005,
Requirement
R11
Retire, P81. This is a
business practice and is
automated in most EMS
software.
BAL-005,
Requirement
R12
Retire, P81. This in the
ACE equation so does
not need to be repeated.
The PRT disagreed with the IERR, as Requirement R8
establishes the minimum expectation of how often
ACE must be calculated by all Balancing Authorities.
However, as written, Requirement R8 provides no
provisions for abnormal or emergency operations
when the automated calculation of ACE may not be
available. The PRT recommendations include that
the SDT revise the Requirement with the proper
context of a minimum normal scan rate and clarify
how frequently all components must be factored
into the Reporting ACE equation under normal
operation. With respect to the sub-requirements,
the SDT should ensure that any proposed revisions
accommodate abnormal and emergency operations,
including the possibility that the EMS or supporting
telemetry may not be available, such as during an
evacuation to a backup site. The PRT notes that the
SDT should consider a requirement focused on a
minimum scan-rate expectation under normal
operations, rather than a requirement that could be
interpreted as if systems have 100% availability.
The PRT agreed with the IERR to retire Requirement
R9, as the Interchange values are included the
definition of Reporting ACE.
The PRT agreed with the IERR as the definition of
Reporting ACE includes the provision that Scheduled
Net Interchange (NIs) used in the Reporting ACE
calculation include Dynamic Schedules.
The PRT agreed with the IERR, as the definition of
Reporting ACE includes the provision that the effect
of schedule ramps be included in the value
Scheduled Net Interchange (NIs) used in the
Reporting ACE calculation.
The PRT agreed with the IERR to retire Requirement
R12 as written. However, the intent of certain sub
requirements still needs to be captured and written
as applicable to Tie-Line, Pseudo-Ties and Dynamic
Schedules. The PRT recommends a new
requirement where each respective Adjacent
BAalancing Authority has agreed to common
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
8
BAL-005,
Requirement
R13
Retire, P81. This is after
the fact and is
automated in most EMS
software.
measuring points that produce an agreed-to
common value to be included in the calculation of
Reporting ACE. Accuracy and review of the agreedto common value is reflected in the new
requirement requiring comparison of hourly
megawatt-hour values against the integrated data
operated to for Tie-Lines, Dynamic Schedules, and
Pseudo-Ties. The SDT should review the
requirement as it relates to current practices to
ensure the reliability needs are met.
The PRT disagreed with the IERR on some aspects of
R13. The PRT suggests deleting the first sentence of
R13, and suggests that the SDT include in a guideline
document the practice of performing hourly error
checks of the NIA operated to for the hour against
an end-of-the-hour reference.
The PRT also recommends a separate requirement
specific to adjustments as needed to the Reporting
ACE to reflect the meter error adjustment.
However, the PRT is concerned that requiring
correction of a component of ACE when in error (no
matter how negligible) would be problematic in that
not all errors require correction. The PRT
recommends that the SDT consider stating the
requirement in such a manner that I ME is required to
be zero except during times needed to compensate
for any data or equipment error affecting a
component of the Reporting ACE calculation
(Interchange or frequency). The SDT should also
allow in this requirement for other means of
addressing metering corrections, which may include
possible revision to real-time metering data. Uses of
the I ME term in the Reporting ACE may also be an
appropriate subject for the guideline document the
PRT is recommending that the SDT develop to
accompany BAL-005 covering some of the suggested
best practices.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
9
BAL-005,
Requirement
R16
BAL-006,
Requirement
R1
BAL-006,
Requirement
R2
Retire, This is a guide for
the quality of the EMS
system. Provide to the
2009-02 team for
consideration.
Retire. This is only for
energy accounting.
Covered by tagging
requirements
Retire. This is only for
energy accounting.
Covered by tagging
requirements.
The PRT agreed with the IERR to retire Requirement
R16 contingent upon addressing one provision. The
PRT recommends moving the requirement for
flagging bad data to revisions made in Requirement
R14.
The PRT agreed with the IERR that R1 is an energy
accounting requirement and should be retired;
however, the PRT recommends that the
SDT determine if there is merit in developing a
reliability metric specific to this standard to measure
performance to certain requirements under BAL006, where the SDT may consider including the
calculation of Inadvertent Interchange. In
development of any metric, the PRT recommends
that the SDT determine the appropriate time-frame
for reliability (as close to real-time as possible).
Similar to how BAL-001-2 has CPS1 and BAAL
measures dependent upon the BA calculating its
Reporting ACE without a stated requirement that
“Each BA shall calculate its Reporting ACE”, the PRT
felt that if the industry supports a measure being
developed that uses Inadvertent Interchange in the
measure of performance, that the BA would
calculate Inadvertent Interchange as needed to
comply. Also, similar to the approach taken for
defining Reporting ACE in the Glossary with all of the
components necessary for the calculation, the PRT is
recommending in Requirement R2 below that the
definition of Inadvertent Interchange also be
updated so that all components necessary for the
calculation are identified.
The PRT agreed with the IERR that R2 is an energy
accounting requirement and recommends
retirement contingent upon the SDT incorporating
Requirement R2 into a revised definition of
Inadvertent Interchange. The PRT recommends that
this definition be modified to capture that the
calculation is on an hourly basis and includes the
megawatt-hour values for Tie-Lines, Pseudo-Ties,
and Dynamic Schedules, along with other scheduled
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
10
BAL-006,
Requirement
R3
Retire. This is only for
energy accounting.
Covered by tagging
requirements
(automated).
BAL-006,
Requirement
R4
Retire. This is only for
energy accounting.
Covered by tagging
requirements
(automated).
interchange implemented under block scheduling,
which does not include the effect of the ramps. The
PRT recommends that the definition also include the
NERC definitions of On-Peak Accounting and OffPeak Accounting, which reference the NAESB
business practice for inadvertent interchange
accounting. The PRT also recommends that the
definition clarify the treatment of scheduled and
actual interchange associated with asynchronous
ties between Interconnections.
The PRT disagreed with the IERR but recommends
incorporating Requirement R3 into BAL-005, as the
requirement relates to the agreement on common
values used in Real-time and also recommends
developing a guideline to cover the practice of
comparing the hourly megawatt-hour values
gathered at the end of the hour against the hourly
integrated values of the scan-rate data operated to,
in order to determine if significant error exists.
The PRT disagreed with the IERR, as it is important
to reliability that Adjacent Balancing Authorities
agree on the scheduled and actual Interchange
between them on a timely basis as a means to
detect when errors may exist so that they can be
corrected in operations. The PRT recommends that
the SDT review current practices for confirmation for
interchange after-the-fact to determine and justify a
shorter duration for agreement on such values for
reliability purposes. The PRT also recommends that
Requirement R4 be restated to require that the
agreement is based upon the aggregate net
schedules and net actuals by adjacent BAs as further
defined in the new definition of Inadvertent
Interchange. In concept, every Tie-Line, Pseudo-Tie,
and Interchange Schedule (including Dynamic
Schedules), implemented in the Reporting ACE
calculation should have an accompanying after-thefact megawatt-hour value accounted for in the
calculation of Inadvertent Interchange.
Requirement R4 Part 4.2 might be addressed in the
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
11
BAL-006,
Requirement
R5
Retire. This is only for
energy accounting.
Covered by tagging
requirements
(automated).
new definition of Inadvertent Interchange by the
proposed reference to On-Peak Accounting and OffPeak Accounting. The SDT should review this
requirement to determine what elements of the
requirement are necessary to support reliability.
The SDT also should consider including in a guideline
document a practice to support providing operations
personnel with information on the comparison of
monthly revenue class meters to meters used for
real-time operation.
The PRT could not agree with the IERR without
investigation by the SDT. The SDT should review
whether the practice that requires BAs to mutually
agree by the 15th calendar day is needed for
reliability. The PRT believes there may be merit in
requiring BAs to identify the cause of the dispute,
and to either correct it within a prescribed number
of days, or follow a dispute resolution process. The
SDT should ensure that the requirement is clear and
distinct, which may require modifying or striking the
language regarding dispute resolution.
2. Clarity: If the Reliability Standard has an Interpretation, CAN, or issue associated with it, or is
frequently violated because of ambiguity, it probably needs to be revised for clarity. Beyond these
indicators, is there any reason to believe that the Reliability Standard should be modified to
address a lack of clarity? Consider:
a. Is this a Version 0 Reliability Standard?
b. Does the Reliability Standard have obviously ambiguous language or language that requires
performance that is not measurable?
c. Are the requirements consistent with the purpose of the Reliability Standard?
Yes
No
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
12
Please summarize your assessment: The BARC 2 PRT recommends the development of a reference
document to clarify the requirements in BAL-005 and BAL-006, and recommends revising the
following sections of BAL-005 and BAL-006 to improve clarity of the standards:
BAL-005
The BARC2 PRT has completed its review of BAL-005, and among other recommendations,
proposes certain revisions below which would remove references to the types of resources and
reserves utilized by the Balancing Authority to balance resources and demand. The PRT
recommendations focus on the components that make up the Reporting ACE, and not on the
ancillary service aspects of resource control that drew criticism from the industry for being specific
to generation when BAL-005 was originally filed with the FERC. Among other recommendations,
for the implementation of Tie-Lines, Pseudo-Ties, and Dynamic Schedules (all similar in that they
utilize real-time data from an agreed-upon common source between Adjacent BAs), the PRT
recommends requirements focused on the real-time values operated to. The PRT
recommendations for BAL-005 are:
1) Title: The PRT recommends changing the title of BAL-005 to “Balancing Authority Control” to
remove the implication that BAL-005 pertains exclusively to generation, and better reflect the
focus on the BA acquiring necessary data to calculate Reporting ACE so that balancing of
resources and demand can be achieved under Tie-Line Bias Control. Based upon the input from
the industry, the PRT recommends that the SDT consider whether the term AGC should be
retained within any requirements. The PRT also recommends that the SDT pursue revisions to
the definition of AGC as proposed below to be resource-neutral.
AGC: Equipment that automatically adjusts generation resources utilized in a Balancing Authority Area from
a central location to maintain the Balancing Authority’s Reporting ACE within the bounds required under the
NERC Reliability Standards. Resources utilized under AGC may include conventional generation, variable
energy resources, storage devices and loads acting as resources, such as Demand Response. may
interchange schedule plus Frequency Bias. AGC may also accommodate automatic inadvertent payback and
time error correction.
2) Purpose: The Standards Drafting Team (SDT) tasked with implementing the SAR developed by
the PRT should consider revising the “Purpose” statement to focus on acquiring the information
necessary for calculating Reporting ACE, while remaining neutral on the types of reserves or
resources utilized. The PRT recommends the following for SDT consideration:
This standard establishes requirements for acquiring necessary data for the Balancing
Authority so that balancing of resources and demand can be achieved under Tie-Line
Bias Control
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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The PRT also recommends that the SDT consider addressing the Hydro Quebec exception for tie
line bias control in some form, or a single-BA exception.
3) Applicability: The SDT should remove “Generator Operators”, “Transmission Operators”, and
“Load Serving Entities” as applicable entities unless used in the SDT’s suggested revisions of this
standard. For example, the SDT discussed that the ownership of metering and other factors
may drive why the LSE is included in this standard, along with other entities, however
consideration should be given to moving requirements for facilities to be within a BA Area to a
FAC standard. The PRT is concerned that removing any requirements of the LSE, TOP, and GOP
and not reflecting them within another standard may inadvertently transfer certain obligations
to the BA to ensure that such loads, resources, and facilities are within their metered
boundaries. The SDT should ensure that any suggested revisions address this concern and
should also consider placing a comparable requirement in a FAC Standard.
4) Requirement R1: The PRT recommends that the content of Requirement R1 be split between
what is needed for ensuring facilities are within a BA Area prior to MW being generated or
consumed, and what is needed for ensuring balanced operation within an Interconnection.
First, the PRT recommends that the SDT consider continuing discussions with the FAC SDT on
moving and restating or clarifying the TOP, LSE, and GOP requirements in a FAC Standard to
ensure facilities are within the metered boundaries of a BA prior to transmission operation,
resource operation, or load being served. The SDT should explore whether the role of the TOP
would appropriately cover the loads interconnected to that TOP such that the LSE requirement
may not be necessary. Second, the PRT recommends that the SDT revise Requirements R1 and
R2 to be BA requirements that all Actual Net Interchange and Scheduled Net Interchange used
by the BA in its Reporting ACE calculation, have an Adjacent BA, as proposed in the redlined
Requirements R1 and R2. Note that the PRT does not intend the proposed language to impose
any additional requirements on the BA that currently apply to the LSE, GOP, and TOP, but
believes that the requirements to identify the applicable BA should perhaps be in the
interconnection agreements or a FAC requirement. With respect to proposed Requirement R2,
the SDT should ensure that the requirement cannot be misinterpreted to imply that Dynamic
Schedules can only be with physically adjacent BAs. The intent is to address adjacency in a
manner consistent with the scheduling path no differently than used for interchange schedules.
5) Requirement R2: Retirement approved by FERC effective January 21, 2014.
6) Requirement R3: The PRT recommends that the SDT not use the term “Regulation Service,” as
in general this statement could apply to implementation of Dynamic Schedules or Pseudo-Ties,
and the desire to have a common point for the data shared between the BAs implementing the
Dynamic Transfer. The PRT recommends removing “adequate” and “Burden” from the
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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requirement. The PRT recommends expanding Requirement R3 to be applicable to the
implementation of tie lines, Pseudo-Ties, and Dynamic Schedules, as all require agreement
between adjacent BAs on the agreed-upon points to be implemented. The PRT recommends
that the SDT review the other standards such as TOP-005 to assure there is no duplication or
redundancy. Specific to the concern on swapping hourly values in BAL-005, the PRT
recommends deleting the proposed R3.2 and the first sentence of the proposed R3.5.2, the PRT
also recommends the SDT develop a guideline document to accompany BAL-005 covering some
of the suggested best practices.
7) Requirement R4: The PRT reviewed Requirement R4 with respect to what notification or
coordination is necessary that could be considered with the other requirements around
Interchange. Initially the PRT was considering a recommendation that the SDT consider the
requirement as it applies to Dynamic Transfer implementation as discussed in the Dynamic
Transfer reliability guideline, and as it applies to the practice of implementing multiple-BA
Dynamic Transfers under a process referred to as ACE Diversity Interchange. The PRT also
considered recommendations to delete or modify Requirement R4 so that it requires
communication with not only the BAs but any other affected entities, and to strike “providing
Regulation Service.” However, after further review, the PRT recommends retiring Requirement
R4, as the basis for coordination of common values between adjacent BAs is covered in
Requirement R3, and correction of information not available has also been addressed. These
requirements should ensure that any failure to perform would be reflected in the BA
performance under BAL-001-2.
8) Requirement R5: The PRT recommends retiring Requirement R5, as the requirements placed
upon the implementation of Dynamic Transfers are covered within Requirement R3. With
respect to having a backup plan to the extent that a service may no longer be provided, the PRT
believes this would be in the terms of the business arrangement. As proposed by the PRT, the
requirements remaining in BAL-005 would ensure that any failure to perform would be
reflected in the BA performance under BAL-001-2.
9) Requirement R6: The PRT recommends that the sentence “Single Balancing Authorities
operating asynchronously may employ alternative ACE calculations such as (but not limited to)
flat frequency control” be captured in the definition of “Reporting ACE.”. The terms used in the
Requirement R6 need to be consistent with those used in Reporting ACE if the Requirement is
retained. The SDT should consider whether the 30-minute requirement for RC notification is
sufficient or excessive. The PRT recommends that if a timing requirement remains in the
standard that it be structured in a manner to not require communication with the RC if the
capability to calculate Reporting ACE is restored within the defined notification period.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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10) Requirement R7: The PRT recommends retiring this Requirement under Paragraph 81. The first
sentence covers having a functional EMS or other system capable of calculating Reporting ACE
and controlling resources, which can be done manually without any detriment to reliability.
EOP-008-1 Requirement R1 recognizes that such automated capability may not be available for
up to two hours for loss of control center functionality. In addition, the second sentence is not
needed, as such actions would be covered under EOP-008. The PRT believes that the term
“Operating AGC” in Requirement R7 refers to the capability to continuously calculate ACE (not
automatic control of resources), which should be considered one of the BAs functional
obligations with regard to the reliable operations and situational awareness of the BES. Though
redundancy and other provisions may be in place to maintain EMS functionality, there are times
when the information may not be available where the provisions under EOP-008-1 would apply.
11) Requirement R8: The PRT recommends that the SDT revise the Requirement with the proper
context of a minimum normal scan rate and clarify how frequently all components must be
factored into the Reporting ACE equation under normal operation. With respect to the subrequirements, the SDT should ensure that any proposed revisions accommodate abnormal and
emergency operations, including the possibility that the EMS or supporting telemetry may not
be available, such as during an evacuation to a backup site. The PRT notes that the SDT should
consider a requirement focused on a minimum scan-rate expectation under normal operations,
rather than a requirement that could be interpreted as if systems have 100% availability.
12) Requirement R8, Part 8.1: The BA should have visibility of system frequency within parameters
consistent with EOP-008, however the PRT recommends that the requirement not be
prescriptive. The SDT should review EOP-008 to ensure the intent of this requirement is
covered there, and to ensure consistency among the standards. In addition, the SDT should
also consider remote and redundant frequency resources to the extent that the information
otherwise available to the BA may not be available upon loss of control center functionality.
Such capability may already be anticipated under EOP-008. The SDT should consider the
following questions in the development of the revised requirement:
a) How much time is allowed to pass if the redundancy is lost before it must be restored?
b) Does the PRT believe it is acceptable for the second and independent frequency device
to be one used by another Balancing Authority?
13) Requirement R9, Part 9.1: The PRT recommends retiring this Requirement. The Actual Net
Interchange and Scheduled Net Interchange values in the Reporting ACE calculation include
provisions for the Balancing Authority to include its high voltage direct (HVDC) link to another
asynchronous interconnection. By assuring the values are handled consistently in the actual and
scheduled Interchange terms included in the real-time Reporting ACE by definition, the
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
16
Balancing Authority is not being instructed “how” to implement the HVDC link, but allowed to
decide the method it will use. By focusing on real-time Reporting ACE, we are assuring
reliability is addressed and maintained at all times. The PRT suggests that the Balancing
Authority during an audit may be asked to provide evidence that its HVDC link was included or
was not included in Reporting ACE under the provisions allowed by definition.
14) Requirements R10 and R11: The PRT recommends the retirement of these requirements, as
the basics of both requirements are factored into the definition of Scheduled Net Interchange
(NIs) used in the Reporting ACE calculation as defined in the NERC Glossary.
The PRT noted that Requirement R10 is written as if “Net Scheduled Interchange” is the value
used in the ACE equation; however, Net Scheduled Interchange has two meanings – the
algebraic sum of all Interchange Schedules across a given path, or between Balancing
Authorities for a given period or instant in time. Aside from the concern of having a definition
with two different meanings, the PRT believes that neither choice in the definition accurately
depicts the value inserted into the ACE or Reporting ACE, which would be the algebraic sum of
all Net Scheduled Interchange with all Adjacent Balancing Authorities, including Dynamic
Schedules. In addition, the PRT could not find a definition of Scheduled Interchange as used in
Requirement R11. Under Section 3 below, the PRT recommends changes to certain NERC
definitions.
15) Requirement R12: The PRT took a holistic approach to Requirement R12 and other
requirements related to the implementation of Tie-Lines, Pseudo-Ties, and Dynamic Schedules,
as all relate to the information exchanged between adjacent BAs.
The PRT recommends a new Requirement R3 related to the implementation of Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, where each respective Adjacent BA has agreed to
common measuring points that produce an agreed-to value to be included in the calculation of
Reporting ACE. The SDT should review the requirement as it relates to current practices to
ensure the reliability needs are met.
The PRT suggests that the holistic approach shall only be achieved if there is a comprehensive
definition of ACE. Therefore the PRT recommends the ACE and Reporting ACE definitions be
reviewed (understanding and identifying as well why there is a difference) to assure that they
are comprehensive (including items such as all AC Tie-Lines, Pseudo-ties, and all other
necessary Adjacent BA information). As the comprehensive details of the ACE calculation in
BAL-001-1 will be retired upon implementation of BAL-001-2, where ACE will only be defined in
the NERC Glossary, the PRT suggests that a complete review of all the NERC Standards is
necessary to assure where ACE is utilized in a Standard, that any update to the ACE definition
would not impact any other Standard.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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16) Requirement R13: The PRT suggests deleting the first sentence of R13, and suggests that the
SDT include in a guideline document the practice of performing hourly error checks of the NI A
operated to for the hour against an end-of-the-hour reference.
The PRT also recommends a separate requirement specific to adjustments as needed to the
Reporting ACE to reflect the meter error adjustment. However, the PRT is concerned that
requiring correction of a component of ACE when in error (no matter how negligible) would be
problematic in that not all errors require correction. The PRT recommends that the SDT
consider stating the requirement in such a manner that I ME is required to be zero except during
times needed to compensate for any data or equipment error affecting a component of the
Reporting ACE calculation (Interchange or frequency). The SDT should also allow in this
requirement for other means of addressing metering corrections, which may include possible
revision to real-time metering data. Uses of the I ME term in the Reporting ACE may also be an
appropriate subject for the guideline document the PRT is recommending that the SDT develop
to accompany BAL-005 covering some of the suggested best practices.
17) Requirement R14: The PRT recommends that the SDT delete the first sentence in R14 and
revise the second sentence to cover the minimum amount of information expected for the BA
to provide in real-time to its operatormade the recommendation reflected in the proposed
redline to define minimum expectations for situational awareness of the BES. The PRT also
recommends that the individual components of actual and scheduled interchange with each
Adjacent Balancing Authority also be captured (Tie-Lines, Pseudo-Ties, Dynamic Schedules,
block schedules as needed for coordination, and real-time schedules). Based on industry
comments, the SDT should consider whether this requirement is needed in the BAL standards,
whether it is adequately covered elsewhere in the standards, or whether it should be moved to
the NERC Rules of Procedure for certification of the Functional Entity.
18) Requirement R15: The SDT should consider continued coordination with the Project 2010-02
FAC SDT on potentially placing a requirement in FAC with respect to supporting infrastructure
or functionality, or review EOP-008 to determine if existing requirements adequately address
primary control center functionality.
19) Requirement R16: The PRT recommends moving the requirement for flagging bad data to
revisions made in Requirement R14.
20) Requirement R17: The PRT recommends that this requirement be written to be specific to the
equipment used to determine the frequency component required for Reporting ACE. The PRT
also recommends that the SDT recommend moving any accuracy requirements applicable to
the needs of the Transmission Operator, which may include MW, MVAR, voltage, potential
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
18
transformer, current transformer, and remote terminal unit or equivalent to a TOP or FAC
standard. Further study would be needed on the “.25% of full scale” and the “appropriate
accuracy” language.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
19
BAL-006
The BARC2 PRT has completed its review of BAL-006 and recommends that it be revised. The
recommendations below include moving any requirements with implications to real-time operations
into BAL-005.
Among other work, the review team considered a FERC directive that recommended the development
of a metric to bound the magnitude of inadvertent accumulations, as those accumulations may be
indicative of a Balancing Authority excessively leaning on the resources of others in its Interconnection.
The review team consensus was that an Inadvertent Interchange accumulation value alone cannot
yield useful information concerning whether a Balancing Authority is operating reliably. The PRT
document on the consideration of issues and directives more fully covers the PRT recommendations
related to the FERC directives. The PRT recommendations for BAL-006 are:
1) Purpose: As the revisions proposed for BAL-006 focus on the minimum requirements for
Adjacent Balancing Authorities to agree upon the hourly MW amounts of scheduled and actual
Interchange between them, which reinforces that errors in coordination or process will be
identified, the PRT recommends that the SDT revise the Purpose statement to be consistent
with the Requirements as further developed under the SAR posted with this recommendation.
2) Requirement R1: The PRT recommends removing Requirement R1 as written and recommends
that the SDT determine if there is merit in developing a reliability metric specific to this
standard including the calculation of Inadvertent Interchange in a reliability metric to measure
performance to certain requirements under BAL-0065, where the SDT may consider including
the calculation of Inadvertent Interchange. In development of any metric, the PRT recommends
that the SDT determine the appropriate time-frame for reliability (as close to real-time as
possible). Similar to how BAL-001-2 has CPS1 and BAAL measures dependent upon the BA
calculating its Reporting ACE without a stated requirement that “Each BA shall calculate its
Reporting ACE”, the PRT felt that if the industry supports a measure being developed that uses
Inadvertent Interchange in the measure of performance, that the BA would calculate
Inadvertent Interchange as needed to comply. Also, similar to the approach taken for defining
Reporting ACE in the Glossary with all of the components necessary for the calculation, the PRT
is recommending in Requirement R2 below that the definition of Inadvertent Interchange also
be updated so that all components necessary for the calculation are identified.
3) Requirement R2: The PRT recommends incorporating R2 into a revised definition of
Inadvertent Interchange: The PRT recommends that this definition be modified to capture that
the calculation is on an hourly basis and includes the megawatt-hour values for Tie-Lines,
Pseudo-Ties, and Dynamic Schedules, along with other scheduled interchange implemented
under block scheduling, which does not include the effect of the ramps. The PRT recommends
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20
that the definition also include the NERC definitions of On-Peak Accounting and Off-Peak
Accounting, which reference the NAESB business practice for inadvertent interchange
accounting. The PRT also recommends that the definition clarify the treatment of scheduled
and actual interchange associated with asynchronous ties between Interconnections.
4) Requirement R3: The PRT recommends incorporating Requirement R3 into BAL-005, as the
requirement relates to the agreement on common values used in Real-time and also
recommends developing a guideline to cover the practice of comparing the hourly megawatthour values gathered at the end of the hour against the hourly integrated values of the scanrate data operated to, in order to determine if significant error exists.
5) Requirement R4: With respect to Requirement R4, the SDT should review current practices for
confirmation for interchange after-the-fact to determine and justify a shorter duration for
agreement on such values for reliability purposes. The PRT also recommends that Requirement
R4 be restated to require that the agreement is based upon the aggregate net schedules and
net actuals by adjacent BAs as further defined in the new definition of Inadvertent Interchange.
In concept, every Tie-Line, Pseudo-Tie, and Interchange Schedule (including Dynamic
Schedules), implemented in the Reporting ACE calculation should have an accompanying afterthe-fact megawatt-hour value accounted for in the calculation of Inadvertent Interchange.
6) Requirement R4, Part 4.2: The SDT should evaluate whether this requirement is addressed in
the new definition of Inadvertent Interchange by the proposed reference to On-Peak
Accounting and Off-Peak Accounting.
7) Requirement R4, Part 4.3: The SDT should review this requirement to determine what
elements of the requirement are necessary to support reliability. The SDT also should consider
including in a guideline document a practice to support providing operations personnel with
information on the comparison of monthly revenue class meters to meters used for real-time
operation.
8) Requirement R5: The SDT should review whether the practice that requires BAs to mutually
agree by the 15th calendar day is needed for reliability. The PRT believes there may be merit in
requiring BAs to identify the cause of the dispute, and to either correct it within a prescribed
number of days, or follow a dispute resolution process. The SDT should ensure that the
requirement is clear and distinct, which may require modifying or striking the language
regarding dispute resolution.
3. Definitions: Do any of the defined terms used within the Reliability Standard need to be refined?
Yes
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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No
Please explain: The SDT should review definitions for consistency on Scheduled Interchange and
clarification of Pseudo-Tie to indicate that it is treated no differently than tie line metering for a
common point between two BAs, communication requirements, etc., and included in the calculation
of Actual Net Interchange and the Reporting ACE equation. The SDT should also review proposed
changes to the INT standards as part of this examination.
The use of multiple Interchange terms within the Standards prompted the PRT to reference the
Glossary of Terms Used in NERC Reliability Standards. The PRT reviewed the definitions of
Actual Net Interchange and Scheduled Net Interchange used within the definition of Reporting
ACE, along with the definitions of Interchange Schedule, Net Interchange Schedule, Net
Scheduled Interchange, and Net Actual Interchange. The PRT found it confusing to have
multiple interchange definitions with similar titles, and some with similar meanings, and
recommends the SDT consider the following:
a) Scan all of the NERC Standards, all terms in BAL-005 and -006, and the NERC Glossary to
determine if the terms associated with the subject standards are used or defined
appropriately (e.g., NI S , NI A , I S , I A , ACE, and Reporting ACE).
b) Ensure that any suggested revisions to scheduled interchange definitions retain the
overall concepts that:
- the schedule ramps must be reflected in the Reporting ACE;
- the static schedules (any that are not Dynamic Schedules) coordinated between
Adjacent BAs prior to implementation use block accounting ignoring the schedule
ramps;
- the estimated MW values of the Dynamic Schedules prior to implementation are
typically not included in the scheduled interchange values coordinated and agreed to
between Adjacent BAs; and
- the megawatt-hour values of scheduled interchange agreed-to after the fact reflect the
static schedules (any that are not Dynamic Schedules) operated to using block
accounting integrated over the hour but ignoring the ramps, plus the hourly integrated
values for any Dynamic Schedules.
Suggested Revisions to NERC Glossary Definitions:
Automatic Generation Control (“AGC”)
Equipment that automatically adjusts generation resources utilized in a Balancing Authority
Area from a central location to maintain the Balancing Authority’s ACE within the bounds
required under the NERC Reliability Standards. Resources utilized under AGC may
include conventional generation, variable energy resources, storage devices and
loads acting as resources, such as Demand Response. may interchange schedule plus
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
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Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction.
Reporting ACE
The scan rate values of a Balancing Authority’s Area Control Error (ACE) measured in MW,
which includes the difference between the Balancing Authority’s Actual Net Interchange
and its Scheduled Net Interchange, plus its Frequency Bias obligation, plus any known
meter error. In the Western Interconnection, Reporting ACE includes Automatic Time Error
Correction (ATEC).
Reporting ACE
Reporting ACE
Reporting ACE
as follows:
Reporting ACE
+ IATEC
is calculated as follows:
= (NIA í1,S í% )A í)S í,ME
is calculated in the Western Interconnection
= (NIA í1,S í% )A í)S í,ME
Where:
NIA (Actual Net Interchange) is the algebraic sum of actual megawatt transfers across all
Tie Lines and Pseudo-Ties with all Adjacent Balancing Authorities, which may use antialiasing filters as needed to more accurately represent the actual interchange as
determined by the Adjacent Balancing Authorities. Balancing Authorities directly
connected via asynchronous ties to another Interconnection may include or exclude the
actual megawatt transfers on those Tie lines in the calculation of NI A , provided they are
implemented in the same manner for Scheduled Net Interchange.
NIS (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with all Adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude the scheduled
megawatt transfers on those Tie Lines in the calculation of NI S , provided they are
implemented in the same manner for Actual Net Interchange.
B (Frequency Bias Setting) is the Frequency Bias Setting (in negative MW/0.1 Hz) for the
Balancing Authority. 10 is the constant factor that converts the frequency bias setting units
to MW/Hz.
FA (Actual Frequency) is the measured frequency in Hz.
FS (Scheduled Frequency) is 60.0 Hz, except during a time-error correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual
Actual Net Interchange (NI A ) and the cumulative hourly net Interchange energy
measurement (in megawatt-hours).
4. Compliance Elements: Are the compliance elements associated with the requirements (Measures,
Data Retention, Violation Risk Factors (VRF), and Violation Severity Levels (VSL)) consistent with the
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
23
direction of the Reliability Assurance Initiative and FERC and NERC guidelines? If you answered
“No,” please identify which elements require revision, and why:
Yes
No
The standard drafting team will address compliance elements.
5. Consistency with Other Reliability Standards: Does the Reliability Standard need to be revised for
formatting and language consistency among requirements within the Reliability Standard or
consistency with other Reliability Standards? If you answered “Yes,” please describe the changes
needed to achieve formatting and language consistency:
Yes
No
As noted above, the PRT recommends a thorough review of all of the NERC Standards, all terms
in BAL-005 and -006, and the NERC Glossary to determine if the Interchange-related terms
associated with the subject standards are used or defined appropriately. For example, the PRT
noted that BAL-005 R10 is written as if “Net Scheduled Interchange” is the value used in the
ACE equation; however, Net Scheduled Interchange has two meanings – the algebraic sum of all
Interchange Schedules across a given path, or between Balancing Authorities for a given period
or instant in time. Also, the PRT could not find a definition of Scheduled Interchange as used in
BAL-005 R11.
6. Changes in Technology, System Conditions, or other Factors: Does the Reliability Standard need to
be revised to account for changes in technology, system conditions, or other factors? If you
answered “Yes,” please describe the changes and specifically what the potential impact is to
reliability if the Reliability Standard is not revised:
Yes
No
7. Consideration of Generator Interconnection Facilities: Is responsibility for generator
interconnection Facilities appropriately accounted for in the Reliability Standard?
Yes
No
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Guiding Questions:
If the Reliability Standard is applicable to GOs/GOPs, is there any ambiguity about the inclusion of
generator interconnection Facilities? (If generation interconnection Facilities could be perceived to
be excluded, specific language referencing the Facilities should be introduced in the Reliability
Standard.)
If the Reliability Standard is not applicable to GOs/GOPs, is there a reliability-related need for
treating generator interconnection Facilities as transmission lines for the purposes of this Reliability
Standard? (If so, GOs and GOPs that own or operate relevant generator interconnection Facilities
should be explicit in the applicability section of the Reliability Standard.)
As indicated in the detail provided for BAL-005 R1, the PRT proposes that the GOP requirement to
have its resource facilities within the metered boundaries of a BA be moved to an FAC requirement
as no MWs should be generated prior to such arrangements.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
25
Recommendation
The answers to the questions above, along with a preliminary recommendation of the Review Team,
will be posted for a 45-day comment period, and the comments publicly posted. The Review Team will
review the comments to evaluate whether to modify its initial recommendation, and will document
the final recommendation which will be presented to the Standards Committee.
Preliminary Recommendation (to be completed by the Review Team after its review and prior to
posting the results of the review for industry comment):
REAFFIRM
REVISE
RETIRE
Technical Justification (If the Review Team recommends that the Reliability Standard be revised, a draft
SAR may be included and the technical justification included in the SAR): See the attached draft SAR.
Preliminary Recommendation posted for industry comment (date): February 21, 2014
Final Recommendation (to be completed by the Review Team after it has reviewed industry
comments on the preliminary recommendation):
REAFFIRM (This should only be checked if there are no outstanding directives,
interpretations or issues identified by stakeholders.)
REVISE
RETIRE
Technical Justification (If the Review Team recommends that the Reliability Standard be revised, a draft
SAR may be included and the technical justification included in the SAR):
Date submitted to NERC Staff:
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
26
Attachment 1: Results-Based Standards
The fourth question for NERC staff and the Review Team asks if the Reliability Standard needs to be
converted to the results-based standards (RBS) format. The information below will be used by NERC
staff and the Review Team in making this determination.
Transitioning the current body of standards into a clear, concise, and effective body will require a
comprehensive application of the RBS concept. RBS concepts employ a defense-in-depth strategy for
Reliability Standards development where each requirement has a role in preventing system failures,
and the roles are complementary and reinforcing. Reliability Standards should be viewed as a portfolio
of requirements designed to achieve an overall defense-in-depth strategy and comply with the quality
objectives identified in the resource document titled, “Acceptance Criteria of a Reliability Standard.”
Accordingly, the Review Team shall consider whether the Reliability Standard contains results-based
requirements with sufficient clarity to hold entities accountable without being overly prescriptive as to
how a specific reliability outcome is to be achieved. The RBS concept, properly applied, addresses the
clarity and effectiveness aspects of a standard.
A Reliability Standard that adheres to the RBS format should strive to achieve a portfolio of
performance-, risk-, and competency-based mandatory reliability requirements that support an
effective defense-in-depth strategy. Each requirement should identify a clear and measurable expected
outcome, such as: a) a stated level of reliability performance, b) a reduction in a specified reliability
risk, or c) a necessary competency.
a. Performance-Based—defines a particular reliability objective or outcome to be achieved. In its
simplest form, a results-based requirement has four components: who, under what conditions
(if any), shall perform what action, to achieve what particular result or outcome?
b. Risk-Based—preventive requirements to reduce the risks of failure to acceptable tolerance
levels. A risk-based reliability requirement should be framed as: who, under what conditions (if
any), shall perform what action, to achieve what particular result or outcome that reduces a
stated risk to the reliability of the bulk power system?
c. Competency-Based—defines a minimum set of capabilities an entity needs to have to
demonstrate it is able to perform its designated reliability functions. A competency-based
reliability requirement should be framed as: who, under what conditions (if any), shall have
what capability, to achieve what particular result or outcome to perform an action to achieve a
result or outcome or to reduce a risk to the reliability of the bulk power system?
Additionally, each RBS-adherent Reliability Standard should enable or support one or more of the eight
reliability principles listed below. Each Reliability Standard should also be consistent with all of the
reliability principles.
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 reliability of the interconnected bulk power systems shall be assessed, monitored, and
maintained on a wide-area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
If the Reliability Standard does not provide for a portfolio of performance-, risk-, and competencybased requirements or consistency with NERC’s reliability principles, NERC staff and the Review Team
should recommend that the Reliability Standard be revised or reformatted in accordance with the RBS
format.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
28
Attachment 2: Paragraph 81 Criteria
The first question for the Review Team asks if one or more of the requirements in the Reliability
Standard meet(s) criteria for retirement or modification based on Paragraph 81 concepts. 3 Use the
Paragraph 81 criteria explained below to make this determination. Document the justification for the
decisions throughout and provide them in the final assessment in the Periodic Review Template.
For a Reliability Standard requirement to be proposed for retirement or modification based on
Paragraph 81 concepts, it must satisfy both: (i) Criterion A (the overarching criterion); and (ii) at least
one of the Criteria B listed below (identifying criteria). In addition, for each Reliability Standard
requirement proposed for retirement or modification, the data and reference points set forth below in
Criteria C should be considered for making a more informed decision.
C riterion A (Overarching Criterion)
The Reliability Standard requirement requires responsible entities (“entities”) to conduct an activity or
task that does little, if anything, to benefit or protect the reliable operation of the BES.
Section 215(a) (4) of the United States Federal Power Act defines “reliable operation” as: “… operating
the elements of the bulk power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of
system elements.”
Criteria B (Identifying Criteria)
B1. Administrative
The Reliability Standard requirement requires responsible entities to perform a function that is
administrative in nature, does not support reliability and is needlessly burdensome.
This criterion is designed to identify requirements that can be retired or modified with little effect on
reliability and whose retirement or modification will result in an increase in the efficiency of the ERO
compliance program. Administrative functions may include a task that is related to developing
procedures or plans, such as establishing communication contacts. Thus, for certain requirements,
Criterion B1 is closely related to Criteria B2, B3 and B4. Strictly administrative functions do not
inherently negatively impact reliability directly and, where possible, should be eliminated or modified
for purposes of efficiency and to allow the ERO and entities to appropriately allocate resources.
3
In most cases, satisfaction of the Paragraph 81 criteria will result in the retirement of a requirement. In some cases,
however, there may be a way to modify a requirement so that it no longer satisfies Paragraph 81 criteria. Recognizing that,
this document refers to both options.
B2. Data Collection/Data Retention
These are requirements that obligate responsible entities to produce and retain data which document
prior events or activities, and should be collected via some other method under NERC’s rules and
processes.
This criterion is designed to identify requirements that can be retired or modified with little effect on
reliability. The collection and/or retention of data do not necessarily have a reliability benefit and yet
are often required to demonstrate compliance. Where data collection and/or data retention is
unnecessary for reliability purposes, such requirements should be retired or modified in order to
increase the efficiency of the ERO compliance program.
B3. Documentation
The Reliability Standard requirement requires responsible entities to develop a document (e.g., plan,
policy or procedure) which is not necessary to protect reliability of the bulk power system.
This criterion is designed to identify requirements that require the development of a document that is
unrelated to reliability or has no performance or results-based function. In other words, the document
is required, but no execution of a reliability activity or task is associated with or required by the
document.
B4. Reporting
The Reliability Standard requirement obligates responsible entities to report to a Regional Entity, NERC
or another party or entity. These are requirements that obligate responsible entities to report to a
Regional Entity on activities which have no discernible impact on promoting the reliable operation of
the BES and if the entity failed to meet this requirement there would be little reliability impact.
B5. Periodic Updates
The Reliability Standard requirement requires responsible entities to periodically update (e.g.,
annually) documentation, such as a plan, procedure or policy without an operational benefit to
reliability.
This criterion is designed to identify requirements that impose an updating requirement that is out of
sync with the actual operations of the BES, unnecessary, or duplicative.
B6. Commercial or Business Practice
The Reliability Standard requirement is a commercial or business practice, or implicates commercial
rather than reliability issues.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
30
This criterion is designed to identify those requirements that require: (i) implementing a best or
outdated business practice or (ii) implicating the exchange of or debate on commercially sensitive
information while doing little, if anything, to promote the reliable operation of the BES.
B7. Redundant
The Reliability Standard requirement is redundant with: (i) another FERC-approved Reliability Standard
requirement(s); (ii) the ERO compliance and monitoring program; or (iii) a governmental regulation
(e.g., Open Access Transmission Tariff, North American Energy Standards Board (“NAESB”), etc.).
This criterion is designed to identify requirements that are redundant with other requirements and are,
therefore, unnecessary. Unlike the other criteria listed in Criterion B, in the case of redundancy, the
task or activity itself may contribute to a reliable BES, but it is not necessary to have two duplicative
requirements on the same or similar task or activity. Such requirements can be retired or modified
with little or no effect on reliability and removal will result in an increase in efficiency of the ERO
compliance program.
C riteria C (Additional data and reference points)
Use the following data and reference points to assist in the determination of (and justification for)
whether to proceed with retirement or modification of a Reliability Standard requirement that satisfies
both Criteria A and B:
C1. Was the Reliability Standard requirement part of a FFT filing?
The application of this criterion involves determining whether the requirement was included in a FFT
filing.
C2. Is the Reliability Standard requirement being reviewed in an ongoing Standards Development
Project?
The application of this criterion involves determining whether the requirement proposed for
retirement or modification is part of an active Standards Development Project, with consideration for
the status of the project. If the requirement has been approved by Registered Ballot Body and is
scheduled to be presented to the NERC Board of Trustees, in most cases it will not need to be
addressed in the periodic review. The exception would be a requirement, such as the Critical
Information Protection (CIP) requirements for Version 3 and 4, that is not due to be retired for an
extended period of time. Also, for informational purposes, whether the requirement is included in a
future or pending Standards Development Project should be identified and discussed.
C3. What is the VRF of the Reliability Standard requirement?
The application of this criterion involves identifying the VRF of the requirement proposed for
retirement or modification, with particular consideration of any requirement that has been assigned as
having a Medium or High VRF. Also, the fact that a requirement has a Lower VRF is not dispositive that
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
31
it qualifies for retirement or modification. In this regard, Criterion C3 is considered in light of Criterion
C5 (Reliability Principles) and C6 (Defense in Depth) to ensure that no reliability gap would be created
by the retirement or modification of the Lower VRF requirement. For example, no requirement,
including a Lower VRF requirement, should be retired or modified if doing so would harm the
effectiveness of a larger scheme of requirements that are purposely designed to protect the reliable
operation of the BES.
C4. In which tier of the most recent Actively Monitored List (AML) does the Reliability Standard
requirement fall?
The application of this criterion involves identifying whether the requirement proposed for retirement
or modification is on the most recent AML, with particular consideration for any requirement in the
first tier of the AML.
C5. Is there a possible negative impact on NERC’s published and posted reliability principles?
The application of this criterion involves consideration of the eight following reliability principles
published on the NERC webpage.
Reliability Principles
NERC Reliability Standards are based on certain reliability principles that define the foundation of
reliability for North American bulk power systems. Each reliability standard shall enable or support
one or more of the reliability principles, thereby ensuring that each standard serves a purpose in
support of reliability of the North American bulk power systems. Each reliability standard shall also
be consistent with all of the reliability principles, thereby ensuring that no standard undermines
reliability through an unintended consequence.
Principle 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.
Principle 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.
Principle 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.
Principle 4. Plans for emergency operation and system restoration of interconnected bulk
power systems shall be developed, coordinated, maintained, and implemented.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
32
Principle 5. Facilities for communication, monitoring, and control shall be provided, used, and
maintained for the reliability of interconnected bulk power systems.
Principle 6. Personnel responsible for planning and operating interconnected bulk power
systems shall be trained, qualified, and have the responsibility and authority to implement
actions.
Principle 7. The reliability of the interconnected bulk power systems shall be assessed,
monitored, and maintained on a wide-area basis.
Principle 8. Bulk power systems shall be protected from malicious physical or cyber attacks.
(footnote omitted).
C6. Is there any negative impact on the defense in depth protection of the BES?
The application of this criterion considers whether the requirement proposed for retirement or
modification is part of a defense in depth protection strategy. In order words, the assessment is to
verify whether other requirements rely on the requirement proposed for retirement or modification to
protect the BES.
C7. Does the retirement or modification promote results or performance based Reliability
Standards?
The application of this criterion considers whether the requirement, if retired or modified, will
promote the initiative to implement results- and/or performance-based Reliability Standards.
BARC Phase 2 Periodic Review Recommendation to Revise BAL-005-0.2b and BAL-006-2
33
Unofficial Nomination Form
Project 2010-14.2 Balancing Authority Reliability-based Control
Standard Drafting Team
Please return this form as soon as possible. If you have any questions, please contact Darrel Richardson
at [email protected].
By submitting the following information, you are indicating your willingness and agreement to actively
participate in the Standard Drafting Team (SDT) meetings if appointed to the SDT by the Standards
Committee. This means that if you are appointed to the SDT, you are expected to attend all (or at least
the vast majority) of the face-to-face SDT meetings as well as participate in all the SDT meetings held via
conference calls, and failure to do so shall result in your removal from the SDT.
Project 2010-14.2 Balancing Authority Reliability-based Control
Project 2010-14.2 focuses on implementing the recommendations from the five year review team and
closing out Directives from FERC Order 693. The standards involved are:
x
x
BAL-005-0.2b – Automatic Generation Control
BAL-006-2 – Inadvertent Interchange
The Project 2010-14.2 standard drafting team is proposed to consist of a maximum of 10 members.
Additional information about the project is available on the project page. Standard drafting team
members should have experience in one or more of the following areas: transmission operations,
Balancing Authority operations including AGC operation, generation operations, and inadvertent
interchange. In addition, team members with experience in compliance, legal, regulatory and
technical writing is desired. Previous drafting team experience is beneficial, but not a requirement.
Experience with developing standards inside or outside (e.g., IEEE, NAESB, ANSI, etc.) of the NERC
process is beneficial, but is not required, and should be highlighted in the information submitted if
applicable.
Electronic Nomination Form
Name:
Organization:
Address:
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team:
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
Unofficial Nomination Form
Project 2010-14.2 BARC Standard Drafting Team
2
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
1
Name:
Telephone:
Organization:
E-mail:
Name:
Telephone:
Organization:
E-mail:
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form
Project 2010-14.2 BARC Standard Drafting Team
3
Standards Announcement
Project 2010-14.2 Balancing Authority Reliability-based Control
Standard Authorization Request
BAL-005 and BAL-006
Informal Comment Period Now Open through August 14, 2014
Standard Drafting Team Nomination Period Open through July 30, 2014
Now Available
A 30-day informal comment period for the Project 2010-14.2 Balancing Authority Reliability-based
Control Standard Authorization Request (SAR) is now open through 8 p.m. Eastern on Thursday,
August 14, 2014.
Background information for this project can be found on the project page.
Instructions for Commenting
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.
Instructions for Submitting a Nomination
If you are interested in serving on the Standard Drafting Team, please complete the nomination form
by July 30, 2014. The nomination form should be submitted describing the individual’s experience or
qualifications related to the project.
Link to Official Nomination Form
An unofficial Word version of the nomination form is posted on the Standard Drafting Team
Vacancies page and the project page.
For more information on the Standards Development Process, please refer to the Standard
Processes Manual.
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 2010-14.2 BARC | July 2014
2
Standards Announcement
Project 2010-14.2 Balancing Authority Reliability-based Control
Standard Authorization Request
BAL-005 and BAL-006
Informal Comment Period Now Open through August 14, 2014
Standard Drafting Team Nomination Period Open through July 30, 2014
Now Available
A 30-day informal comment period for the Project 2010-14.2 Balancing Authority Reliability-based
Control Standard Authorization Request (SAR) is now open through 8 p.m. Eastern on Thursday,
August 14, 2014.
Background information for this project can be found on the project page.
Instructions for Commenting
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.
Instructions for Submitting a Nomination
If you are interested in serving on the Standard Drafting Team, please complete the nomination form
by July 30, 2014. The nomination form should be submitted describing the individual’s experience or
qualifications related to the project.
Link to Official Nomination Form
An unofficial Word version of the nomination form is posted on the Standard Drafting Team
Vacancies page and the project page.
For more information on the Standards Development Process, please refer to the Standard
Processes Manual.
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 2010-14.2 BARC | July 2014
2
Individual or group. (19 Responses)
Name (8 Responses)
Organization (8 Responses)
Group Name (11 Responses)
Lead Contact (11 Responses)
Contact Organization (11 Responses)
Question 1 (18 Responses)
Question 1 Comments (18 Responses)
Question 2 (18 Responses)
Question 2 Comments (18 Responses)
Question 3 (14 Responses)
Question 3 Comments (18 Responses)
Question 4 (0 Responses)
Question 4 Comments (18 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
BAL-006 Requirement R4 was recommended to be retired by the independent Expert
Recommnedation Report (IERR) as it was only for energy accounting. The Periodic Review Team
(PRT) disagreed with the IERR claiming that there was a reliability concern if adjacent BAs did not
agree to NSI and NAI in a timely manner. The accounting occurs after the fact. Can the PRT provide
examples of what reliability issues the revised requirement would guard against? What would a new
“timely basis” be? As long as the agreement between BAs continues to be after the fact, regardless
of the “timely basis”, there isn’t a potential reliability issue and agrees with the IERR
recommendation in favor of retiring the requirement. The new definition of Inadvertent Interchange
will still be covered by the revised requirements R1 and R2 if requirement R4 is retired as per the
IERR recommendation.
No
Individual
Thomas Foltz
American Electric Power
Yes
There needs to be a mechanism to allow the BA to gather what they need from the other functional
entities in calculating ACE. It appears that the SAR may lead in a direction that removes the TOP,
LSE, and GOP from the standard, leaving “stranded obligations” where no requirements remain
which would obligate the TOP, LSE, or GOP to provide the BA what it needs. The SAR states that
consideration is being given to include similar oblibations as part of a FAC standard, however we are
not certain we could support the proposed changes to BAL-005 without also seeing exactly how it
will be addressed in the FAC standard(s). In addition, rather than adding such obligations solely to a
FAC standard, AEP believes the best approach would be to add the obligation as a separate
requirement within BAL-005 (as a real time obligation) *and* the FAC standard (as a forward
looking obligation). The SAR removes the GOP, TOP, and LSE from the standard while also stating
the drafting team’s intent to explore whether the role of TOP could assume the obligations of the
LSE. The TOP and LSE are separate entities with unique obligations as specified in the NERC
glossary. Requiring the TOP to assume the obligations of the LSE could prove very problematic,
blurring roles which are currently well defined.
No
No
AEP is not aware of any Canadian provincial or other regulatory requirements that may need to be
considered during this project in order to develop a continent-wide approach to the standard(s).
Individual
Greg Travis
Idaho Power
No
No
No
Group
MRO NERC Standards Review Forum
Joe DePoorter
Madison Gas & Electric
Yes
The general scope of the SAR is fine. The challenge is the SAR covers the entire scope recommended
by the Periodic Review Team. The PRT work was out for comment and to our knowledge no changes
were made to the PRT’s recommendations based on comments received. We had concerns with
some of the PRT proposals and the previous comments should be addressed prior to substantive
work.
Yes
ERCOT and HQ do not have Inadvertent Interchange. Additionally, any material changes to BAL-006
would need to be coordinated with NAESB.
Yes
While there are Order No. 693 directives for these standards, several of these directives may have
become immaterial (e.g. directive may be to make a paragraph 81-type change) or counterproductive at this point. The drafting team should focus on creating streamlined high-quality resultsbased standards. If a directive causes a problem or does not add value to reliability, the drafting
team should document their reasoning and not blindly make changes.
As we are unsure of what was done with our prior comments from April, we are providing them
here. General Comments on BAL-005 • We agree with streamlining the standard and making it
clearer. • While we are OK with changing the title of the standard, we have concerns about removing
the term “Automatic Generation Control”. This term is or its acronym are used well over 50 times in
the standards and are commonly understood in the industry (tens of thousands of references to it on
the internet). Given the intent of the FERC directive, we propose changing the exiting definition in
the NERC glossary to : Equipment that automatically adjusts generation and other resources in a
Balancing Authority Area from a central location to maintain the Balancing Authority’s interchange
schedule plus Frequency Bias. AGC may also accommodate automatic inadvertent payback and time
error correction. • We agree with removing all entities other than Balancing Authorities in the
applicability section, but disagree with moving some of the requirements to a FAC standard (reasons
explained below). Specific Comments on BAL-005 • On the current R1 (and R3), we agree with
removing the requirements about generation, load and transmission be within the metered bounds
of a BA. These requirements also should not be punted to a FAC standard. These were “control area
criteria” (i.e. concepts) that were swept into the V0 standard. The proof that all load, generation and
transmission is within metered bounds is achieved via Inadvertent Accounting. There is no need for
a different explicit requirement. BAs should be the only applicable entity in this standard. • On the
current R3 and R4: We believe these requirements are important and generally should remain as-is
(although they could be consolidated). We also believe that avoidance of Burden (a defined and
understandable term) is a reasonable objective for the requirement(s). • The current R5 would not
be necessary if all BAs had to report their control performance. The problem is the current practice
whereby BAs who receive overlap regulation don’t have to report their performance. Thus, we
believe this requirement should stay. It only applies to a relatively small proportion of BAs. • With
regard to the redline R2, the team appears to be duplicating requirements in the INT standards. A
BA should not be subject to multiple non-compliances for missing a schedule. • With regard to the
redline R3, R3.1 is a piece of information and not a requirement. R3.4 is redundant with the parent
requirement. There is no requirement today to swap hourly values, and this should not be added. •
The redline R3.5 should be simplified to “ACE source data shall be acquired and ACE calculated at
least every 6 seconds). R3.5.2. is redundant with R3.2 and should be eliminated. General Comments
and Comments on PRT Recommendations for BAL-006 • We agree with eliminating the redundant
requirements and moving the real-time requirements to BAL-005. • On the PRT recommendation for
R1, we disagree with the proposal to add a performance metric with regard to inadvertent
interchange. The other balancing standards adequately address the reliability impact of imbalance. •
On the PRT recommendation for R2, we disagree with the need to change the definition of
Inadvertent Interchange to add the complexity mentioned. If both parties to a transaction agree to a
common number and have operated against common points in real time, it makes no difference to
the Interconnection. • On the PRT recommendation for R3, we disagree with the need to “swap”
hourly values. There are many tools in place to detect significant and persistent metering and
balancing errors. There has not been a need to call an AIE survey for at least 5 years. At most, we
would suggest a requirement in BAL-005 for each BA to share in real time its NIa with each adjacent
BA and its RC as well as share its NIs with its RC. This would accommodate the “cross check” the
PRT appears to be seeking. If this requirement were added, the other proposed “granular”
requirements in BAL-005 on pseudo-ties and dynamic schedules could likely be simplified. This
adjacent information is already an implied requirement in Attachment 1-TOP-005. • On the PRT
recommendation for R4 and its sub-requirements, we disagree with the suggestion of adding
complexity to the definition of Inadvertent Interchange and of performing and reporting more
frequently as well as the suggestion again for a performance requirement. • On the PRT
recommendation for R5, we believe the current requirement is acceptable as-is. • The proposed
changes to definitions look acceptable. Specific Comments on BAL-006 • On the redline R1.3 and
R1.4, these should be changed to reflect the current practice that monthly data is to be submitted
and agreed to with counterparties in the Inadvertent Interchange reporting portal.
Individual
Leonard Kula
Independent Electricity System Operator
Yes
BAL-006 Requirement R4 was recommended to be retired by the Independent Expert
Recommendation Report (IERR) as it was only for energy accounting. The Periodic Review Team
(PRT) disagreed with the IERR claiming that there was a reliability concern if Adjacent BA's did not
agree to NSI and NAI in a timely manner. The IESO questions this concern, given that the
accounting occurs after-the-fact. Can the PRT provide examples of what reliability issues the revised
requirement would guard against? What would a new "timely basis" be? As long as the the
agreement between BA's continues to be after-the-fact, regardless of the "timely basis", the IESO
does not see a potential reliability issue and agrees with the IERR recommendation in favour of
retiring the requirement. The new definition of Inadvertent Interchange will still be covered by the
revised Requirement 1 and 2 if requirement 4 was to be retired as per the IERR recommendation.
No
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
Marcus Pelt
Southern Company Compliance
No
No
No
Individual
Eric Scott
Ameren
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
Yes
In the 3rd line of the Objectives section, delete the 2nd ‘define’. Be consistent with the capitalization
of Real-time throughout the SAR. For BAL-005 Reword the end of the next-to-last sentence in the
overview of BAL-005 on Page 3 to read: ‘…the PRT recommends requirements which are focused on
Real-time operating data. Effectively changing the definition of AGC may be confusing since AGC is
an acronym for automatic generation control. You can take generation out of the definition but AGC
will always be automatic generation control. We suggest a total change of the term. If it is to
reference control of all resources, why not label it automatic resource control (ARC). Then the
acronym fits the terminology. Purpose – While concurring with the proposed change to the purpose,
we suggest replacing ‘under’ with ‘using’. Also, since Tie Line Bias is the defined term not Tie Line
Bias control, don’t capitalize control. In the sentence following the proposed purpose, capitalize Tie
Line Bias and insert ‘interconnection’ between ‘single-BA’ and ‘exception’. Applicability – We suggest
modifying this to read: ‘The SDT should remove “Generator Operators”, “Transmission Operators”,
and “Load Serving Entities” as applicable entities unless they are specifically included in a standard
requirement by the SDT.’ Requirement R1 – In the 4th line insert ‘regarding’ between ‘FAC SDT’ and
‘moving’. Requirement R3 – The sentence in the 9th line that reads ‘Specific to the concern on
swapping hourly values in BAL-005 posted for industry comment.’ doesn’t make any sense. Has
something been left out? Split the next sentence into two sentences by replacing the comma after
‘R3.5.2’ with a period and capitalizing ‘The’ to begin the second sentence. Requirement R6 – Delete
the ‘the’ at the end of the 3rd line. Requirement R7 – In the last line replace the ‘where’ with ‘and’.
Requirement R9, Part 9.1 – Rewrite the last sentence to read: ‘By focusing on Real-time Reporting
ACE, the PRT assures reliability is addressed and maintained at all times.’ Requirement R14 –
Replace the ‘for’ in the next-to-last line with ‘and considered during’.
No
No
There were several documents (redlined standards, Consideration of Comments, directives and
issues, IERP recommendations) mentioned in the Unofficial Comment Form which indicated they
were included in this posting but they aren’t on the project page.
Individual
Karin Schweitzer
Texas Reliability Entity, Inc.
Yes
BAL-005 1) Purpose statement: Texas Reliability Entity, Inc. (Texas RE) requests that the purpose
statement be revised to remove “under Tie-Line Bias Control.” ERCOT has only DC ties modeled as
internal generation or load and effectively utilizes only freqency bias control. 2) R3.2 and 1st
sentence of R3.5.2: Texas RE requests the rationale for moving hourly error checking from
Requirement R3.2 and R3.5.2 to a guideline document be clearly documented within the draft
revision. 3) R13: Texas RE requests the rationale for moving hourly error checking from
Requirement R13 to a guideline document be clearly documented within the draft revision. BAL-006
While the ERCOT region does not have issues with coordination of accounting figures between
Adjacent Balancing Authorities, Texas RE supports the proposed revisions.
No
The issues which are unique to the ERCOT region would be addressed by the suggested changes
made by Texas RE in response to Question 1 for BAL-005.
No
Group
Bureau of Reclamation
Erika Doot
Power Resources Office
Yes
The Bureau of Reclamation supports the drafting team’s recommendation to remove Generator
Operators (GOPs), Transmission Operators (TOPs), and Load Serving Entities (LSEs) from the scope
of BAL-005. Reclamation believes that generation and transmission interconnection requirements
ensure that facilities are within the metered boundaries of a Balancing Authority area before they
are placed in service. Reclamation notes that this requirement has imposed a compliance paperwork
burden on GOPs, TOPs, and LSEs because Balancing Authorities are not required to provide
information confirming that facilities are within the metered boundaries of a balancing authority area
under the standard, and this effort has not provided a corresponding reliability benefit. In the
alternative, Reclamation suggests that Balancing Authorities be required to coordinate to ensure that
all facilities fall within their metered boundaries because BAs determine the boundaries.
No
No
Group
Duke Energy
Michael Lowman
Duke Energy
No
No
No
Comments: Duke Energy thanks the Periodic Review Team for their efforts, and would like to
express our support for the recommendations made. The following comments are suggestions for
the standard drafting team’s consideration. General Comment re: BAL-005:Unless the Standard
Drafting Team chooses to revise, a re-post of the red-lined version of the current BAL-005 is
necessary so that it may accurately reflect the numbering of the original version. Duke Energy
agrees with the PRT’s recomendation that the NERC Glossary of Terms defintion of ACE and
Reporting ACE should be reviewed. In addition, we agree that a comprehensive review of the NERC
standards is necessary to ensure that any updates/revsions to the NERC definitions mentioned
above would not impact other NERC Reliability Standards. 1) Requirement 1: Duke Energy echoes
the concerns of the Periodic Review Team in ensuring to keep responsibility of staying in a metered
boundary with the LSE, TOP, and GOP. We do not agree with the possibility of placing this
responsibility with the BA. 2) Requirement 13: We agree with the approach suggested by the
Periodic Review Team. Also, we support the development of a guideline document to further expand
on the topic, and clarify any potential ambiguities that may exist. 3)Requirement 14: Duke Energy is
in agreement with the industry comments referenced by the Periodic Review Team for this
requirement. If covered elsewhere, we feel that this requirement should be retired.
Group
ISO Standards Review Committee
Terry Bilke
MISO
Yes
The SRC supports the comments included in BAL-005, R1 regarding the correct boundaries for
applicability to the BA versus LSE, TOP and GOP for specific obligations.
Yes
ERCOT and HQ do not have Inadvertent Interchange. Additionally, any material changes to BAL-006
would need to be coordinated with NAESB.
Yes
While there are Order No. 693 directives for these standards, several of these directives may have
become immaterial (e.g. directive may be to make a paragraph 81-type change) or counterproductive at this point. The drafting team should focus on creating streamlined high-quality resultsbased standards. If a directive causes a problem or does not add value to reliability, the drafting
team should document their reasoning and not blindly make changes.
The general scope of the SAR is fine. The challenge is the SAR covers the entire scope recommended
by the Periodic Review Team and also references a separate document. A SAR is intended to set the
general bounds of a standard. Our approval of the SAR does not imply we agree with everything
included. We strongly request that the previous comments submitted earlier in the year be
addressed prior to substantive work.
Group
DTE Electric Co.
Kathleen Black
NERC Training & Standards Development
No
No
No
We agree that R15 of BAL-005 belongs in EOP-008.
Individual
Jo-Anne Ross
Manitoba Hydro
No
No
Group
Bonneville Power Administration
Jamison Dye
Transmission Reliability Standards Group
No
No
No
Group
ACES Standards Collaborators
Ben Engelby
ACES
Yes
We agree we the SAR’s recommendation to revise BAL-005 and BAL-006. We support the 5-year
review team's recommendation of removing the TOP, GOP, and LSE functions from the applicability
section of BAL-005 and to retire or consolidate several requirements. We also support the team’s
recommendations to retire many of the requirements in BAL-006.
No
We are not aware of regional variances or business practices that need to be considered.
No
We are not aware of any Canadian provincial or other regulatory requirements that need to be
considered.
We will provide specific comments on the proposed changes to the standards after the SAR is
approved and the formal standards development process begins. Thank you for the opportunity to
comment.
Individual
Chris Scanlon
Exelon companies, BGE, ComEd, PECO
No
No
No
Exelon recognizes that this is a large Project. We appreciate the scope of the proposed changes and
encourage the drafting team to be cautious so as to not re-assign obligations to other entities if
requirements are “mapped” to other Standards. In general, Exelon agrees with the changes
proposed in the SAR and to changes in the applicability, including the removal of the LSE. We note
however, changes to LSE applicable requirements need to be considered in light of the RRB
initiative. Exelon believes that applicability for R17 is solely to the Balancing Authority; we agree
with the PRT recommendation that BAL-005 R17 be written to be specific to the equipment used to
determine the frequency component required for reporting ACE as is detailed in the interpretation
effective 8/27/2008 in BAL-005-0.2.b for R17. See Appendix 1 which limits the requirement to BA
frequency monitoring.
Group
Associated Electric Cooperative, Inc. - JRO00088
Phil Hart
Associated Electric Cooperative, Inc. - NCR01177
Yes
The PRT has argued the IERP recommendation stating hourly meter checkouts are not a reliability
related task, but purely economic. AECI agrees with the PRT that it is a helpful process in identifying
errors in tie values, however as long as an entities ACE is established, (which is required by other
standards) no real risk to reliability is taken, merely economic settlement on the errors within the
meters. The PRT has created a requirement that addresses identifying and troubleshooting errors
with interchange (draft BAL-005 R3.5.2), without requiring specific hourly checkouts of every meter
on the system. This is something entities are extremely concerned with for economic reasons so
there is no doubt the action will be performed, but creating this as a requirement only creates
administrative burden without any additional benefit to reliability (NAI error checks are already
required in R3.5.2). For this reason, the currently drafted BAL-005 R3.2 is redundant with R3.5.2.
AECI requests that the SDT strike R3.2.
No
No
Individual
Richard Vine
California ISO
Yes
The ISO supports the comments submitted by the ISO/RTO Council Standards Review Committee
Yes
The ISO supports the comments submitted by the ISO/RTO Council Standards Review Committee
BAL-005 requirement R8 presently states: “The Balancing Authority shall ensure that data
acquisition for and calculation of ACE occur at least every six seconds." In order for this requirement
to have the desired effect of ensuring a Balancing Authority’s ACE value is refreshed and accurate as
of every six seconds, the tie line metering data being sampled by each Balancing Authority must
also be accurate and updated at least every six seconds. Therefore, the ISO recommends that the
SAR include within its scope the requirement for ensuring the tie line meter data being relied on for
the “data acquisition for and calculation of ACE” is updated at least every six seconds to match the
required sampling frequency.
Consideration of Comments
Project 2010-14.2 Periodic Review of BAL Standards
The Project 2010-14.2 Drafting Team thanks all commenters who submitted comments on the
Standards Authorization Request (SAR). These standards were posted for a 30-day public comment
period from July 16, 2014 through August 14, 2014. Stakeholders were asked to provide feedback on
the standards and associated documents through a special electronic comment form. There were 19
sets of comments, including comments from approximately 95 different people from approximately 75
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.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process. If you feel there has been an error or omission,
you can contact the Director of Standards, Howard Gugel, at 404-446-9693 or by e-mail. 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/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf
1.
2.
3.
4.
Do you have any specific questions or comments relating to the scope
of the proposed standard action or any component of the SAR outside
of the pro forma standard? .............................................................................. 9
If you are aware of the need for a regional variance or business
practice that should be considered with this phase of the project,
please identify it here .....................................................................................17
Are you aware of any Canadian provincial or other regulatory
requirements that may need to be considered during this project in
order to develop a continent-wide approach to the standard(s)? If
yes, please identify the jurisdiction and specific regulatory
requirements ..................................................................................................20
If you have any other comments on this SAR that you haven’t already
mentioned, please provide them here .............................................................23
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
2
Greg Campoli
Sylvain Clermont
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
Gerry Dunbar
Peter Yost
Kathleen Goodman
Michael Jones
4.
5.
6.
7.
8.
9.
NPCC 10
NPCC 1
NPCC 2
National Grid
ISO - New England
NPCC 1
NPCC 2
Consolidated Edison Co. of New York, Inc. NPCC 3
Northeast Power Coordinating Council
Hydro-Quebec TransEnergie
Nw York Independent System Operator
NPCC 3
NPCC 10
3.
Orange and Rockland Utilities Inc.
David Burke
2.
New York State Reliability Council, LLC
Region Segment Selection
Northeast Power Coordinating Council
Additional Organization
Guy Zito
Organization
Alan Adamson
Additional Member
Group
Commenter
1.
.
1.
Group/Individual
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
1
2
3
4
5
6
7
8
Registered Ballot Body Segment
9
X
10
Ontario Power Generation, Inc.
Utility Services
Hydro One Networks Inc.
National Grid
New York Power Authority
Orange and Rockland Utilties Inc.
Joe DePoorter
18. David Ramkalawan
19. Brian Robinson
20. Ayesha Sabouba
21. Brian Shanahan
22. Wayne Sipperly
23. Ben Wu
2.
Dan Inman
Dave Rudolph
Kayliegh Wilkersonq Lincoln Electric System
Jodi Jensen
Joe DePoorter
Ken Goldsmith
Mahmood Safi
3.
4.
5.
6.
7.
8.
9.
MRO
MRO
MRO
MRO
MRO
Great River Energy
Minnesota Power
Rochester Public Utilties
MidAmerican Energy
Wisconsin Public Service
Nebraska Public Power District
11. Mike Brytowski
12. Randi Nyholm
13. Scott Nickels
14. Terry Harbour
15. Tom Breene
16. Tony Eddleman
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
1, 3, 5
3, 4, 5, 6
1, 3, 5, 6
4
1, 5
1, 3, 5, 6
2
1, 3, 5, 6
4
3, 4, 5, 6
1
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
MISO
10. Marie Knox
Omaha Public Power District
Alliant Energy
1, 6
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5
1, 3, 5, 6
Region Segment Selection
Western Area Power Administration MRO
Madison Gas & Electric
NPCC 1
NPCC 5
NPCC 1
NPCC 1
NPCC 8
NPCC 5
NPCC 1
MRO NERC Standards Review Forum
Basin Electric Power Cooperative
Minnkota Power Cooperative
Otter Tail Power Company
Chuck Wicklund
2.
Xcel Energy
Amy Casuccelli
1.
Additional Member
Additional Organization
Hydro-Quebec TransEnergie
17. Si Truc Phan
Group
The United Illuminating Company
16. Robert Pellegrini
NPCC 1
NPCC 10
NPCC 6
NPCC 5
New York Power Authority
13. Bruce Metruck
NPCC 9
NPCC 2
Northeast Power Coordinating Council
New Brunswick Power Corporation
12. Alan MacNaughton
15. Lee Pedowicz
Independent Electricity System Operator
11. Helen Lainis
NPCC 1
Organization
14. Silvia Parada Mitchell NextEra Energy, LLC
Northeast Utilities
Commenter
10. Mark Kenny
Group/Individual
X
2
X
3
X
4
X
5
X
6
4
7
8
Registered Ballot Body Segment
9
10
Phil Hart
Stephanie Johnson Westar Energy
Bo Jones
Allen Klassen
Tiffany Lake
Shannon Mickens
James Nail
3.
4.
5.
6.
7.
8.
9.
Michael Lowman
Duke Energy
3
5
6
2. Lee Schuster
3. Dale Goodwine
4. Greg Cecil
1
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
1
1. Doug Hils
Additional Member Additional Organization Region Segment Selection
Group
Technical Services Center WECC 1, 5
WECC 5
Power Resources Office
2. George Girgis
Additional Member Additional Organization Region Segment Selection
1. Richard Jackson
6.
4
2
3, 5
2
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5, 6
1, 3, 5, 6
Bureau of Reclamation
Erika Doot
5.
Group
Oklahoma Municipal Power Authority SPP
11. Ashley Stringer
SPP
Southwest Power Pool
SPP
SPP
SPP
SPP
SPP
10. Carl Stelly
City of Independence, MO
Southwest Power Pool
Westar Energy
Westar Energy
Westar Energy
SPP
SERC
SPP
1
Region Segment Selection
SPP Standards Review Group
Associated Electric Cooperative
Cleco Power
Louis Guidry
Organization
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
Sunflower Electric Power Corporation SPP
Allan George
Additional Organization
Robert Rhodes
Marcus Pelt
2.
Additional Member
Group
Group
Commenter
1.
4.
N/A
3.
Group/Individual
X
2
X
X
3
4
X
X
X
5
X
X
6
5
7
8
Registered Ballot Body Segment
9
10
Terry Bilke
Commenter
ISO Standards Review Committee
ACES Standards Collaborators
Additional Organization
Bill Hutchison
Michael Brytowski Great River Energy
Steve McElhaney
Ellen Watkins
Lucia Beal
Scott Brame
Ginger Mercier
2.
3.
4.
5.
6.
7.
8.
Segment
Selection
SERC
SERC
RFC
SPP
SERC
MRO
SERC
1, 2, 3
3, 4, 5
3
1, 2, 3
1, 2, 3
1, 3, 5, 6
1, 5
WECC 1, 4, 5
Region
1
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Prairie Power, Inc.
North Carolina Electric Membership Corporation
Southern Maryland Electric Cooperative, Inc.
Sunflower Electric Power Corporation
South Mississippi Electric Power Association
Southern Illinois Power Cooperative
John Shaver
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.
Ben Engelby
1.
Additional
Member
Group
WECC 1
Electrical Engineer
3. Gordon Markley
WECC 1
Commercial System Management WECC 1
Region Segment Selection
Public Utilities Specialist
10.
5
4
3
Bonneville Power Administration
2. Wes Hutchison
Additional Organization
Jamison Dye
1. Sheryl Welch
Additional Member
Group
DO/SOC
4. Barbara Hollan
9.
Generation Optimization
3. Mark Stefaniak
RFC
NERC Trainng & Standards Development RFC
2. Daniel Herring
RFC
NERC Compliance
Region Segment Selection
DTE Electric Co.
Additional Organization
Kathleen Black
1. Kent Kujala
Additional Member
Group
2
PJM
RFC
ERCOT 2
ERCOT
2
2
6. Cathy Wesley
NPCC
2
2
5. Cheryl Moseley
IESO
3. Ben Li
NPCC
SPP
NPCC
NYISO
4. Kathleen Goodman ISO-NE
SPP
2. Greg Campoli
8.
Organization
Additional Member Additional Organization Region Segment Selection
Group
1. Charles Yeung
7.
Group/Individual
X
2
X
X
3
X
4
X
X
5
X
X
6
6
7
8
Registered Ballot Body Segment
9
10
Mark Ringhausen
Individual
Individual
Individual
Individual
Individual
Individual
14.
15.
16.
17.
18.
19.
Richard Vine
Chris Scanlon
Jo-Anne Ross
Karin Schweitzer
Eric Scott
Leonard Kula
Greg Travis
1, 3
1, 3
1, 3
California ISO
Exelon companies, BGE, ComEd, PECO
Manitoba Hydro
Texas Reliability Entity, Inc.
Ameren
Independent Electricity System Operator
Idaho Power
1
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Individual
SERC
6. Sho-Me Power Electric Cooperative
13.
SERC
5. N.W. Electric Power Cooperative, Inc.
1, 3
1, 3
1, 3
American Electric Power
SERC
4. Northeast Missouri Electric Power Cooperative
Thomas Foltz
SERC
3. M & A Electric Power Cooperative
Individual
1
3, 4
Additional Organization Region Segment Selection
SERC
12.
RFC
RFC
Associated Electric Cooperative, Inc. JRO00088
SERC
Additional Member
Phil Hart
Organization
2. KAMO Electric Cooperative
Group
Hoosier Energy Rural Electric Cooperative, Inc.
Old Dominion Electric Cooperative
Commenter
1. Central Electric Power Cooperative
11.
10. Bob Solomon
9.
Group/Individual
X
X
2
X
X
X
X
X
3
4
X
X
X
X
X
5
X
X
X
X
X
6
7
7
8
Registered Ballot Body Segment
9
X
10
Ameren
Agree
Agree
8
We agree with and support MISO’s comments for
BAL-005 and BAL-006.
Supporting Comments of “Entity Name”
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
Summary Consideration:
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).
No
No
No
No
No
No
Yes
Duke Energy
DTE Electric Co.
Bonneville Power Administration
Idaho Power
Manitoba Hydro
Exelon companies, BGE, ComEd, PECO
Northeast Power Coordinating Council
9
BAL-006 Requirement R4 was recommended to be retired by the
independent Expert Recommnedation Report (IERR) as it was only for
energy accounting. The Periodic Review Team (PRT) disagreed with the
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
No
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
Organization
Yes or No
Do you have any specific questions or comments relating to the scope of the proposed standard action or any component of the
SAR outside of the pro forma standard?
Summary Consideration:
1.
Yes
SPP Standards Review Group
10
In the 3rd line of the Objectives section, delete the 2nd ‘define’.Be
consistent with the capitalization of Real-time throughout the SAR.For BAL005Reword the end of the next-to-last sentence in the overview of BAL-005
on Page 3 to read: ‘...the PRT recommends requirements which are focused
on Real-time operating data.
The SAR provides an outline of what could transpire during the
development/revision of the proposed standard. The SDT will take your
comment into consideration as it reviews the current standard.
The general scope of the SAR is fine. The challenge is the SAR covers the
entire scope recommended by the Periodic Review Team. The PRT work
was out for comment and to our knowledge no changes were made to the
PRT’s recommendations based on comments received. We had concerns
with some of the PRT proposals and the previous comments should be
addressed prior to substantive work.
The SAR provides an outline of what could transpire during the
development/revision of the proposed standard. The SDT will take your
comment into consideration as it reviews the current standard.
IERR claiming that there was a reliability concern if adjacent BAs did not
agree to NSI and NAI in a timely manner. The accounting occurs after the
fact. Can the PRT provide examples of what reliability issues the revised
requirement would guard against? What would a new “timely basis” be?
As long as the agreement between BAs continues to be after the fact,
regardless of the “timely basis”, there isn’t a potential reliability issue and
agrees with the IERR recommendation in favor of retiring the requirement.
The new definition of Inadvertent Interchange will still be covered by the
revised requirements R1 and R2 if requirement R4 is retired as per the IERR
recommendation.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Yes
Yes or No
MRO NERC Standards Review Forum
Organization
Yes or No
Thank you for your comment.
11
Requirement R1 - In the 4th line insert ‘regarding’ between ‘FAC SDT’ and
‘moving’.
Thank you for your comment. The SDT does not believe that the suggested
modification provides for additional clarity.
Applicability - We suggest modifying this to read: ‘The SDT should remove
“Generator Operators”, “Transmission Operators”, and “Load Serving
Entities” as applicable entities unless they are specifically included in a
standard requirement by the SDT.’
Thank you for your comment. The SDT does not believe that the suggested
modification provides for additional clarity.
In the sentence following the proposed purpose, capitalize Tie Line Bias and
insert ‘interconnection’ between ‘single-BA’ and ‘exception’.
The SDT does not reference the phrase “under Tie-Line Bias Control”.
Purpose - While concurring with the proposed change to the purpose, we
suggest replacing ‘under’ with ‘using’. Also, since Tie Line Bias is the
defined term not Tie Line Bias control, don’t capitalize control.
The SDT believes that the term Automatic Generation Control (AGC) should
not be changed since it is used extensively throughout the NERC standards.
Effectively changing the definition of AGC may be confusing since AGC is an
acronym for automatic generation control. You can take generation out of
the definition but AGC will always be automatic generation control. We
suggest a total change of the term. If it is to reference control of all
resources, why not label it automatic resource control (ARC). Then the
acronym fits the terminology.
Thank you for your comments.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
Yes
Yes or No
12
The Bureau of Reclamation supports the drafting team’s recommendation
to remove Generator Operators (GOPs), Transmission Operators (TOPs),
and Load Serving Entities (LSEs) from the scope of BAL-005. Reclamation
believes that generation and transmission interconnection requirements
Thank you for your comment. The SDT does not believe that the suggested
modification provides for additional clarity.
Requirement R14 - Replace the ‘for’ in the next-to-last line with ‘and
considered during’.
Thank you for your comment. The SDT does not believe that the suggested
modification provides for additional clarity.
Requirement R9, Part 9.1 - Rewrite the last sentence to read: ‘By focusing
on Real-time Reporting ACE, the PRT assures reliability is addressed and
maintained at all times.’
Thank you for your comment. The SDT does not believe that the suggested
modification provides for additional clarity.
Requirement R7 - In the last line replace the ‘where’ with ‘and’.
Thank you for your comment.
Requirement R6 - Delete the ‘the’ at the end of the 3rd line.
Thank you for your comment.
Split the next sentence into two sentences by replacing the comma after
‘R3.5.2’ with a period and capitalizing ‘The’ to begin the second sentence.
Thank you for your comment.
Requirement R3 - The sentence in the 9th line that reads ‘Specific to the
concern on swapping hourly values in BAL-005 posted for industry
comment.’ doesn’t make any sense. Has something been left out?
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Bureau of Reclamation
Organization
Yes
Yes
ACES Standards Collaborators
Associated Electric Cooperative, Inc. JRO00088
13
The PRT has argued the IERP recommendation stating hourly meter
checkouts are not a reliability related task, but purely economic.
The SDT agrees with your comment and has removed them from the draft
standard BAL-005. The SDT is still reviewing BAL-006.
We agree we the SAR’s recommendation to revise BAL-005 and BAL-006.
We support the 5-year review team's recommendation of removing the
TOP, GOP, and LSE functions from the applicability section of BAL-005 and
to retire or consolidate several requirements. We also support the team’s
recommendations to retire many of the requirements in BAL-006.
The SDT agrees with your comment and has removed them from the draft
standard.
The SRC supports the comments included in BAL-005, R1 regarding the
correct boundaries for applicability to the BA versus LSE, TOP and GOP for
specific obligations.
The SDT agrees with your comment and has removed them from the draft
standard.
ensure that facilities are within the metered boundaries of a Balancing
Authority area before they are placed in service. Reclamation notes that
this requirement has imposed a compliance paperwork burden on GOPs,
TOPs, and LSEs because Balancing Authorities are not required to provide
information confirming that facilities are within the metered boundaries of
a balancing authority area under the standard, and this effort has not
provided a corresponding reliability benefit. In the alternative, Reclamation
suggests that Balancing Authorities be required to coordinate to ensure
that all facilities fall within their metered boundaries because BAs
determine the boundaries.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Yes
Yes or No
ISO Standards Review Committee
Organization
Yes
Yes or No
14
There needs to be a mechanism to allow the BA to gather what they need
from the other functional entities in calculating ACE. It appears that the SAR
may lead in a direction that removes the TOP, LSE, and GOP from the
standard, leaving “stranded obligations” where no requirements remain
which would obligate the TOP, LSE, or GOP to provide the BA what it needs.
The SAR states that consideration is being given to include similar
oblibations as part of a FAC standard, however we are not certain we could
support the proposed changes to BAL-005 without also seeing exactly how
it will be addressed in the FAC standard(s). In addition, rather than adding
such obligations solely to a FAC standard, AEP believes the best approach
The SDT has modified the draft standard to address your concern in an
equally effective and efficient manner.
The PRT has created a requirement that addresses identifying and
troubleshooting errors with interchange (draft BAL-005 R3.5.2), without
requiring specific hourly checkouts of every meter on the system. This is
something entities are extremely concerned with for economic reasons so
there is no doubt the action will be performed, but creating this as a
requirement only creates administrative burden without any additional
benefit to reliability (NAI error checks are already required in R3.5.2). For
this reason, the currently drafted BAL-005 R3.2 is redundant with R3.5.2.
AECI requests that the SDT strike R3.2.
The SAR provides an outline of what could transpire during the
development/revision of the proposed standard. The SDT will take your
comment into consideration as it reviews the current standard.
AECI agrees with the PRT that it is a helpful process in identifying errors in
tie values, however as long as an entities ACE is established, (which is
required by other standards) no real risk to reliability is taken, merely
economic settlement on the errors within the meters.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
American Electric Power
Organization
Yes
Texas Reliability Entity, Inc.
BAL-005
15
BAL-006 Requirement R4 was recommended to be retired by the
Independent Expert Recommendation Report (IERR) as it was only for
energy accounting. The Periodic Review Team (PRT) disagreed with the IERR
claiming that there was a reliability concern if Adjacent BA's did not agree
to NSI and NAI in a timely manner. The IESO questions this concern, given
that the accounting occurs after-the-fact. Can the PRT provide examples of
what reliability issues the revised requirement would guard against? What
would a new "timely basis" be? As long as the the agreement between BA's
continues to be after-the-fact, regardless of the "timely basis", the IESO
does not see a potential reliability issue and agrees with the IERR
recommendation in favour of retiring the requirement. The new definition
of Inadvertent Interchange will still be covered by the revised Requirement
1 and 2 if requirement 4 was to be retired as per the IERR recommendation.
The SAR provides an outline of what could transpire during the
development/revision of the proposed standard. The SDT will take your
comment into consideration as it reviews the current standard.
The SDT agrees with your comment and has revised both BAL-005 and FAC001 to address your concern.
would be to add the obligation as a separate requirement within BAL-005
(as a real time obligation) *and* the FAC standard (as a forward looking
obligation).The SAR removes the GOP, TOP, and LSE from the standard
while also stating the drafting team’s intent to explore whether the role of
TOP could assume the obligations of the LSE. The TOP and LSE are separate
entities with unique obligations as specified in the NERC glossary. Requiring
the TOP to assume the obligations of the LSE could prove very problematic,
blurring roles which are currently well defined.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Yes
Yes or No
Independent Electricity System
Operator
Organization
Yes
California ISO
16
Thank you for your comment and please review the response to the
ISO/RTO Council SRC.
The ISO supports the comments submitted by the ISO/RTO Council
Standards Review Committee
While the ERCOT region does not have issues with coordination of
accounting figures between Adjacent Balancing Authorities, Texas RE
supports the proposed revisions.
The SAR provides an outline of what could transpire during the
development/revision of the proposed standard. The SDT will take
your comment into consideration as it reviews the current standard.
BAL-006
1) Purpose statement: Texas Reliability Entity, Inc. (Texas RE) requests that
the purpose statement be revised to remove “under Tie-Line Bias
Control.” ERCOT has only DC ties modeled as internal generation or load
and effectively utilizes only freqency bias control.
The SDT does not reference the phrase “under Tie-Line Bias Control”.
2) R3.2 and 1st sentence of R3.5.2: Texas RE requests the rationale for
moving hourly error checking from Requirement R3.2 and R3.5.2 to a
guideline document be clearly documented within the draft revision.
The SDT believes that by using a common data source the possibility for
errors due to different values is minimized.
3) R13: Texas RE requests the rationale for moving hourly error checking
from Requirement R13 to a guideline document be clearly documented
within the draft revision.
This requirement was broken apart and is now a part of Requirements
R1 and R7.
Question 1 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Yes or No
Organization
No
No
No
No
No
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
SPP Standards Review Group
Bureau of Reclamation
Duke Energy
DTE Electric Co.
Question 2 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
No
Northeast Power Coordinating
Council
Organization
Yes or No
17
If you are aware of the need for a regional variance or business practice that should be considered with this phase of the
project, please identify it here
Summary Consideration:
2.
No
No
No
No
No
No
No
No
Yes
ACES Standards Collaborators
Associated Electric
Cooperative, Inc. - JRO00088
American Electric Power
Idaho Power
Independent Electricity
System Operator
Texas Reliability Entity, Inc.
Manitoba Hydro
Exelon companies, BGE,
ComEd, PECO
MRO NERC Standards Review
Forum
18
ERCOT and HQ do not have Inadvertent Interchange. Additionally, any material
changes to BAL-006 would need to be coordinated with NAESB.
Thank you for your comment and please review the response to Question #1.
The issues which are unique to the ERCOT region would be addressed by the
suggested changes made by Texas RE in response to Question 1 for BAL-005.
Thank you for your comment.
We are not aware of regional variances or business practices that need to be
considered.
Question 2 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
No
Yes or No
Bonneville Power
Administration
Organization
Yes
California ISO
19
Thank you for your comment and please review the response to the ISO/RTO Council
SRC.
The ISO supports the comments submitted by the ISO/RTO Council Standards Review
Committee
Thank you for your comment. The SDT will be consulting with NAESB when it is
evaluating BAL-006 for possible revisions.
ERCOT and HQ do not have Inadvertent Interchange. Additionally, any material
changes to BAL-006 would need to be coordinated with NAESB.
Thank you for your comment. The SDT will be consulting with NAESB when it is
evaluating BAL-006 for possible revisions.
Question 2 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Yes
Yes or No
ISO Standards Review
Committee
Organization
No
No
No
No
No
SPP Standards Review Group
Bureau of Reclamation
Duke Energy
DTE Electric Co.
Bonneville Power
Administration
Question 3 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
No
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
Organization
Yes or No
20
Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project
in order to develop a continent-wide approach to the standard(s)? If yes, please identify the jurisdiction and specific regulatory
requirements
Summary Consideration:
3.
No
No
No
No
No
Yes
Yes
Associated Electric
Cooperative, Inc. - JRO00088
American Electric Power
Idaho Power
Texas Reliability Entity, Inc.
Exelon companies, BGE,
ComEd, PECO
MRO NERC Standards Review
Forum
ISO Standards Review
Committee
21
While there are Order No. 693 directives for these standards, several of these
directives may have become immaterial (e.g. directive may be to make a paragraph
81-type change) or counter-productive at this point. The drafting team should focus
Thank you for your comment.
While there are Order No. 693 directives for these standards, several of these
directives may have become immaterial (e.g. directive may be to make a paragraph
81-type change) or counter-productive at this point. The drafting team should focus
on creating streamlined high-quality results-based standards. If a directive causes a
problem or does not add value to reliability, the drafting team should document their
reasoning and not blindly make changes.
Thank you for your comment.
AEP is not aware of any Canadian provincial or other regulatory requirements that
may need to be considered during this project in order to develop a continent-wide
approach to the standard(s).
Thank you for your comment.
We are not aware of any Canadian provincial or other regulatory requirements that
need to be considered.
Question 3 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
No
Yes or No
ACES Standards Collaborators
Organization
Yes or No
Thank you for your comment.
22
on creating streamlined high-quality results-based standards. If a directive causes a
problem or does not add value to reliability, the drafting team should document their
reasoning and not blindly make changes.
Question 3 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
23
o We agree with removing all entities other than Balancing Authorities in the
applicability section, but disagree with moving some of the requirements to a FAC
standard (reasons explained below).
The SDT agrees and has modified the definition in an equally effective manner to that
which you have proposed.
o While we are OK with changing the title of the standard, we have concerns about
removing the term “Automatic Generation Control”. This term is or its acronym are
used well over 50 times in the standards and are commonly understood in the industry
(tens of thousands of references to it on the internet). Given the intent of the FERC
directive, we propose changing the exiting definition in the NERC glossary to :
Equipment that automatically adjusts generation and other resources in a Balancing
Authority Area from a central location to maintain the Balancing Authority’s
interchange schedule plus Frequency Bias. AGC may also accommodate automatic
inadvertent payback and time error correction.
Thank you for your comment.
o We agree with streamlining the standard and making it clearer.
General Comments on BAL-005
As we are unsure of what was done with our prior comments from April, we are
providing them here.
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
MRO NERC Standards Review Forum
Organization
Question 4 Comment
If you have any other comments on this SAR that you haven’t already mentioned, please provide them here
Summary Consideration:
4.
The SDT has modified the requirement to ensure no duplication.
24
o With regard to the redline R2, the team appears to be duplicating requirements in
the INT standards. A BA should not be subject to multiple non-compliances for missing
a schedule.
The SDT has incorporated the intent of these requirements into other requirement
within the standard (Requirements R1 and R8).
o The current R5 would not be necessary if all BAs had to report their control
performance. The problem is the current practice whereby BAs who receive overlap
regulation don’t have to report their performance. Thus, we believe this requirement
should stay. It only applies to a relatively small proportion of BAs.
The SDT has incorporated the intent of these requirements into other requirement
within the standard (Requirements R1 and R8).
o On the current R3 and R4: We believe these requirements are important and
generally should remain as-is (although they could be consolidated). We also believe
that avoidance of Burden (a defined and understandable term) is a reasonable
objective for the requirement(s).
The SDT disagrees with your comment. The SDT believes that Inadvertent Accounting
does not guarantee everything is captured – as proposed R1 and R2 is intended to
capture all facilities within the BA.
o On the current R1 (and R3), we agree with removing the requirements about
generation, load and transmission be within the metered bounds of a BA. These
requirements also should not be punted to a FAC standard. These were “control area
criteria” (i.e. concepts) that were swept into the V0 standard. The proof that all load,
generation and transmission is within metered bounds is achieved via Inadvertent
Accounting. There is no need for a different explicit requirement. BAs should be the
only applicable entity in this standard.
Specific Comments on BAL-005
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
25
o On the PRT recommendation for R3, we disagree with the need to “swap” hourly
values. There are many tools in place to detect significant and persistent metering and
balancing errors. There has not been a need to call an AIE survey for at least 5 years.
o On the PRT recommendation for R2, we disagree with the need to change the
definition of Inadvertent Interchange to add the complexity mentioned. If both parties
to a transaction agree to a common number and have operated against common points
in real time, it makes no difference to the Interconnection.
The SAR provides an outline of what could transpire during the development/revision of
the proposed standard. The SDT will take your comment into consideration as it reviews
the current standard.
o On the PRT recommendation for R1, we disagree with the proposal to add a
performance metric with regard to inadvertent interchange. The other balancing
standards adequately address the reliability impact of imbalance.
The SAR provides an outline of what could transpire during the development/revision of
the proposed standard. The SDT will take your comment into consideration as it reviews
the current standard.
o We agree with eliminating the redundant requirements and moving the real-time
requirements to BAL-005.
General Comments and Comments on PRT Recommendations for BAL-006
The SDT agrees and has made the necessary modifications.
o The redline R3.5 should be simplified to “ACE source data shall be acquired and ACE
calculated at least every 6 seconds). R3.5.2. is redundant with R3.2 and should be
eliminated.
The SDT agrees and has made the necessary modifications.
o With regard to the redline R3, R3.1 is a piece of information and not a requirement.
R3.4 is redundant with the parent requirement. There is no requirement today to swap
hourly values, and this should not be added.
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
26
o On the redline R1.3 and R1.4, these should be changed to reflect the current practice
that monthly data is to be submitted and agreed to with counterparties in the
Inadvertent Interchange reporting portal. The SAR provides an outline of what could
transpire during the development/revision of the proposed standard. The SDT will take
Specific Comments on BAL-006
Thank you for your comment.
o The proposed changes to definitions look acceptable.
development/revision of the proposed standard. The SDT will take your comment into
consideration as it reviews the current standard.
Thank you for your comment. The SAR provides an outline of what could transpire during the
o On the PRT recommendation for R5, we believe the current requirement is
acceptable as-is.
o On the PRT recommendation for R4 and its sub-requirements, we disagree with the
suggestion of adding complexity to the definition of Inadvertent Interchange and of
performing and reporting more frequently as well as the suggestion again for a
performance requirement.
The SAR provides an outline of what could transpire during the development/revision of
the proposed standard. The SDT will take your comment into consideration as it reviews
the current standard.
The SDT disagrees with your comment concerning the swapping of values. The SDT
believes that his practice will help to guarantee a more accurate Reporting ACE value.
At most, we would suggest a requirement in BAL-005 for each BA to share in real time
its NIa with each adjacent BA and its RC as well as share its NIs with its RC. This would
accommodate the “cross check” the PRT appears to be seeking. If this requirement
were added, the other proposed “granular” requirements in BAL-005 on pseudo-ties
and dynamic schedules could likely be simplified. This adjacent information is already
an implied requirement in Attachment 1-TOP-005.
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Organization
Duke Energy
27
Duke Energy agrees with the PRT’s recomendation that the NERC Glossary of Terms
defintion of ACE and Reporting ACE should be reviewed. In addition, we agree that a
comprehensive review of the NERC standards is necessary to ensure that any
The SDT has elected to not provide a redline version of the present standard since the
proposed standard is a complete re-writing of the current standard. The SDT is
providing a Mapping Document so that an entity can see what the SDT is proposing to
be done with the present requirements.
Unless the Standard Drafting Team chooses to revise, a re-post of the red-lined version
of the current BAL-005 is necessary so that it may accurately reflect the numbering of
the original version.
General Comment re: BAL-005:
Comments: Duke Energy thanks the Periodic Review Team for their efforts, and would
like to express our support for the recommendations made. The following comments
are suggestions for the standard drafting team’s consideration.
The SDT agrees and has made the necessary modifications to thee requirement.
BAL-005 requirement R8 presently states: “The Balancing Authority shall ensure that
data acquisition for and calculation of ACE occur at least every six seconds." In order
for this requirement to have the desired effect of ensuring a Balancing Authority’s ACE
value is refreshed and accurate as of every six seconds, the tie line metering data being
sampled by each Balancing Authority must also be accurate and updated at least every
six seconds. Therefore, the ISO recommends that the SAR include within its scope the
requirement for ensuring the tie line meter data being relied on for the “data
acquisition for and calculation of ACE” is updated at least every six seconds to match
the required sampling frequency.
your comment into consideration as it reviews the current standard. However, some
information should be within a guideline paper rather than a standard (guideline is more
of how to accomplish - a standard should not define how to accomplish).
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
California ISO
Organization
The SDT thanks you for your comment and agrees.
28
Exelon recognizes that this is a large Project. We appreciate the scope of the proposed
changes and encourage the drafting team to be cautious so as to not re-assign
obligations to other entities if requirements are “mapped” to other Standards. In
general, Exelon agrees with the changes proposed in the SAR and to changes in the
applicability, including the removal of the LSE. We note however, changes to LSE
applicable requirements need to be considered in light of the RRB initiative. Exelon
believes that applicability for R17 is solely to the Balancing Authority; we agree with
the PRT recommendation that BAL-005 R17 be written to be specific to the equipment
used to determine the frequency component required for reporting ACE as is detailed
in the interpretation effective 8/27/2008 in BAL-005-0.2.b for R17. See Appendix 1
which limits the requirement to BA frequency monitoring.
1) Requirement 1: Duke Energy echoes the concerns of the Periodic Review Team in
ensuring to keep responsibility of staying in a metered boundary with the LSE, TOP,
and GOP. We do not agree with the possibility of placing this responsibility with the
BA.
The SDT agrees and has proposed to move this requirement to FAC-001.
2) Requirement 13: We agree with the approach suggested by the Periodic Review
Team. Also, we support the development of a guideline document to further
expand on the topic, and clarify any potential ambiguities that may exist.
The SDT has moved this requirement into the proposed Requirements R1 and R7.
3) Requirement 14: Duke Energy is in agreement with the industry comments
referenced by the Periodic Review Team for this requirement. If covered
elsewhere, we feel that this requirement should be retired.
The SDT disagrees with your comment. The SDT has moved this requirement into
Requirements R5 and R8.
updates/revsions to the NERC definitions mentioned above would not impact other
NERC Reliability Standards.
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
Exelon companies, BGE, ComEd, PECO
Organization
The SDT thanks you for your comment.
29
We will provide specific comments on the proposed changes to the standards after the
SAR is approved and the formal standards development process begins. Thank you for
the opportunity to comment.
The SDT thanks you for your comment.
We agree that R15 of BAL-005 belongs in EOP-008.
The SDT apologizes for this omission. However, the SDT has revised the standards in
an equally effective and efficient manner than what was originally developed by the
PRT.
There were several documents (redlined standards, Consideration of Comments,
directives and issues, IERP recommendations) mentioned in the Unofficial Comment
Form which indicated they were included in this posting but they aren’t on the project
page.
The SAR provides an outline of what could transpire during the development/revision of
the proposed standard. The SDT will take your comment into consideration as it reviews
the current standard.
The general scope of the SAR is fine. The challenge is the SAR covers the entire scope
recommended by the Periodic Review Team and also references a separate document.
A SAR is intended to set the general bounds of a standard. Our approval of the SAR
does not imply we agree with everything included. We strongly request that the
previous comments submitted earlier in the year be addressed prior to substantive
work.
Question 4 Comment
Consideration of Comments: Project 2010-14.2 Periodic Review of BAL Standards
Posted: July 2015
END OF REPORT
ACES Standards Collaborators
DTE Electric Co.
SPP Standards Review Group
ISO Standards Review Committee
Organization
BALͲ005Ͳ1–BalancingAuthorityControl
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page1of16
BALͲ005Ͳ1–BalancingAuthorityControl
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:
AutomaticGenerationControl(AGC):Centrally located equipment Equipment that
automatically adjusts resources generation in a Balancing Authority Area from a central
location to help maintain the Reporting ACE in that of a Balancing Authority’s Area within
the bounds required by applicable NERC Reliability Standardsinterchange schedule plus
Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction. ResourcesutilizedunderAGCmayinclude,butarenotlimitedto,conventional
generation,variableenergyresources,storagedevicesandloadsactingasresources(suchas
DemandResponse).
ActualFrequency(FA):TheInterconnectionfrequencymeasuredinHertz(Hz).
ActualNetInterchange(NIA):ThealgebraicsumofactualmegawatttransfersacrossallTie
Lines,includingPseudoͲTies,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection.ActualmegawatttransfersonasynchronousDCtielinesthataredirectly
connectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
ScheduledNetInterchange(NIS):Thealgebraicsumofallscheduledmegawatttransfers,
includingDynamicSchedules,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection,includingtheeffectofscheduledramps.Scheduledmegawatttransfers
onasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionareexcludedfrom
ScheduledNetInterchange.
InterchangeMeterError(IME):Aterm,normallyzero,usedintheReportingACEcalculationto
compensatefordataorequipmenterrorsaffectinganyothercomponentsoftheReportingACE
calculation.
AutomaticTimeErrorCorrection(IATEC):TheadditionofacomponenttotheACEequationfor
theWesternInterconnectionthatmodifiesthecontrolpointforthepurposeofcontinuously
payingbackPrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.Automatic
TimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
whenoperatinginAutomaticTimeErrorCorrectionMode.
TheabsolutevalueofIATECshallnotexceedLmax.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page2of16
BALͲ005Ͳ1–BalancingAuthorityControl
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|Bi|andL10,
0.2*|Bi|чLmaxчL10.
x
x
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare
(RMS)valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragiven
year.Thebound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
x
x
Y=Bi/BS.
H=Numberofhoursusedtopaybackprimaryinadvertentinterchangeenergy.Thevalue
ofHissetto3.
x
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
x
x
x
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲBi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontime
monitor,where: ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontime
monitorcontrolcenterclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲ
Peakaccumulationaccountingisrequired,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
ReportingACE:ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError
(ACE)measuredinMWincludesthedifferencebetweentheBalancingAuthorityArea’sActual
NetInterchangeanditsScheduledNetInterchange,plusitsFrequencyBiasSettingobligation,
pluscorrectionforanyknownmetererror.IntheWesternInterconnection,ReportingACE
includesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
x NIA
=
ActualNetInterchange.
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page3of16
BALͲ005Ͳ1–BalancingAuthorityControl
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
x IATEC
=
AutomaticTimeErrorCorrection.
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartotheReporting
ACEdefinedabove.Anymodification(s)tothisspecifiedReportingACEequationthatis(are)
implementedforallBAAsonanInterconnectionandis(are)consistentwiththefollowingfour
principlesofTieLineBiascontrolwillprovideavalidalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofall
BAAs’generation,load,andlossisthesameastotalInterconnectiongeneration,load,
andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimes
andthesumofallBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEterm
correctsforknownmeteringorcomputationalerrors.)
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page4of16
BALͲ005Ͳ1–BalancingAuthorityControl
Whenthisstandardhasreceivedballotapproval,thetextboxeswillbemovedtothe
SupplementalMaterialSectionofthestandard.
A. Introduction
1.
Title:
BalancingAuthorityControl
2.
Number:
BALͲ005Ͳ1
3.
Purpose: Thisstandardestablishesrequirementsforacquiringdatanecessaryto
calculateReportingAreaControlError(ReportingACE).Thestandardalsospecifiesa
minimumperiodicity,accuracy,andavailabilityrequirementforacquisitionofthe
dataandforprovidingtheinformationtotheSystemOperator.
4.
Applicability:
4.1. FunctionalEntities:
4.1.1. BalancingAuthority
4.2. Facilities:
4.2.1. N/A
EffectiveDate: See Implementation Plan
B. Requirements and Measures
RationaleforRequirementR1:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedata(meaning
datafromthesamesource)iscriticaltocalculatingReportingACEthatisconsistent
betweenBalancingAuthorities.Whendatasourcesarenotcommon,confusioncanbe
createdbetweenBAsresultingindelayedorincorrectoperatoraction.
TheintentofRequirementR1istoprovideaccuracyinthemeasurementsand
calculationsusedinReportingACE,hourlyinadvertentenergy,andFrequencyResponse
measurements.Itspecifiestheneedforcommonmeteringpointsforinstantaneousand
hourlyintegratedvaluesforthetielinemegawattflowvaluesbetweenBalancing
AuthorityAreas.Commondatasourcerequirementsalsoapplywhenmorethantwo
BalancingAuthoritiesparticipateinallocatingsharesofagenerationresourceorin
supplementaryregulation,forexample.
R1.
EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,andDynamic
SchedulewithanAdjacentBalancingAuthorityisequippedwithamutuallyagreedͲ
upontimesynchronizedcommonsourcetodeterminehourlymegawattͲhourvalues.
[ViolationRiskFactor:Medium][TimeHorizon:OperationsPlanning]
1.1. ThesevaluesshallbeexchangedbetweenAdjacentBalancingAuthorities.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page5of16
BALͲ005Ͳ1–BalancingAuthorityControl
M1. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodetermineiftheBalancingAuthorityanditsadjacentBalancing
Authorityhaveagreeduponatimesynchronizedcommonsourcetodetermine
megawattͲhourvalues.
RationaleforRequirementR2:RealͲtimeoperationofaBalancingAuthorityrequires
realͲtimeinformation.AsufficientscanrateiskeytoanOperator’strustinrealͲtime
information.Withoutasufficientscanrate,anoperatormayquestiontheaccuracyof
dataduringeventswhichwoulddegradetheoperator’sabilitytomaintainreliability.
R2.
TheBalancingAuthorityshalluseascanrateofnomorethansixsecondsinacquiring
datanecessarytocalculateReportingACE.[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]
M2. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthedata
necessarytocalculateReportingACEwasscannedatarateofnomorethansix
seconds.Acceptableevidencemayincludehistoricaldata,datedarchivefiles;ordata
fromotherdatabases,spreadsheets,ordisplaysthatdemonstratecompliance.
RationaleforRequirementR3:TheRCisresponsibleforcoordinatingthereliabilityof
bulkelectricsystemsformemberBA’s.WhenaBAisunabletocalculateitsACEforan
extendedperiodoftime,thisinformationmustbecommunicatedtotheRCsothatthe
RChassufficientknowledgeofsystemconditionstoassessanyunintendedreliability
consequencesthatmayoccuronthewidearea.
R3.
ABalancingAuthoritythatisunabletocalculateReportingACEformorethan30Ͳ
consecutiveminutesshallnotifyitsReliabilityCoordinatorwithin45minutesofthe
beginningofaninabilitytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M3. EachBalancingAuthoritywillhavedatedrecordstoshowwhenitwasunableto
calculateReportingACEformorethan30consecutiveminutesandthatitnotifiedits
ReliabilityCoordinatorwithin45minutesofthebeginningofaninabilitytocalculate
ReportingACE.Suchevidencemayinclude,butisnotlimitedto,datedvoice
recordings,operatinglogs,orothercommunicationdocumentation.
RationaleforRequirementR4:Frequencyisthebasicmeasurementforinterconnection
health,andacriticalcomponentforcalculatingReportingACE.Withoutsufficient
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page6of16
BALͲ005Ͳ1–BalancingAuthorityControl
availablefrequencydatatheBAoperatorwilllacksituationalawarenessandwillbe
unabletomakecorrectdecisionswhenmaintainingreliability.
R4.
EachBalancingAuthorityshallusefrequencymeteringequipmentforthecalculation
ofReportingACE:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
4.1. thatisavailableaminimumof99.95%foreachcalendaryear;and,
4.2. withaminimumaccuracyof0.001Hz.
M4. TheBalancingAuthorityshallhaveevidencesuchasdateddocumentsorother
evidenceinhardcopyorelectronicformatshowingthefrequencymetering
equipmentusedforthecalculationofReportingACEhadaminimumavailabilityof
99.95%foreachcalendaryearandhadaminimumaccuracyof0.001Hzto
demonstratecompliancewithRequirementR4.
RationaleforRequirementR5:SystemoperatorsutilizeReportingACEasaprimary
metrictodetermineoperatingactionsorinstructions.WhendatainputsintotheACE
calculationareincorrect,theoperatorshouldbemadeawarethroughvisualdisplay.
Whenanoperatorquestionsthevalidityofdata,actionsaredelayedandtheprobability
ofadverseeventsoccurringcanincrease.
R5.
TheBalancingAuthorityshallmakeavailabletotheoperatorinformationassociated
withReportingACEincluding,butnotlimitedto,qualityflagsindicatingmissingor
invaliddata.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtimeOperations]
M5. EachBalancingAuthorityAreashallhaveevidencesuchasagraphicaldisplayordated
alarmlogthatprovidesindicationofdatavalidityfortherealͲtimeReportingACE
basedonboththecalculatedresultandalloftheassociatedinputstherein.
RationaleforRequirementR6:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthatReportingACE
besufficientlyavailabletoassurereliability.
R6.
EachBalancingAuthority’ssystemusedtocalculateReportingACEshallbeavailablea
minimumof99.5%ofeachcalendaryear.[ViolationRiskFactor:Medium][Time
Horizon:OperationsAssessment]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page7of16
BALͲ005Ͳ1–BalancingAuthorityControl
M6. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
systemnecessarytocalculateReportingACEhasaminimumavailabilityof99.5%for
eachcalendaryear.Acceptableevidencemayincludehistoricaldata,datedarchive
files;ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR7:ReportingACEisameasureoftheBA’sreliability
performanceforBALͲ001,andBALͲ002.Withoutaprocesstoaddresspersistenterrorsin
theACEcalculation,theoperatorcanlosetrustinthevalidityofReportingACEresulting
indelayedorincorrectdecisionsregardingthereliabilityofthebulkelectricsystem.
R7.
EachBalancingAuthoritythatiswithinamultipleBalancingAuthorityInterconnection
shallimplementanOperatingProcesstoidentifyandmitigateerrorsaffectingthe
scanͲrateaccuracyofdatausedinthecalculationofReportingACEforeachBalancing
AuthorityArea.[ViolationRiskFactor:Medium][TimeHorizon:SameͲdayOperations
]
M7. EachBalancingAuthorityshallhaveacurrentOperatingProcessmeetingthe
provisionsofRequirementR7andevidencetoshowthattheprocesswas
implemented,suchasdatedcommunicationsorincorporationinSystemOperator
taskverification.
RationaleforRequirementR8:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedataiscriticalto
calculatingReportingACEthatisconsistentbetweenBalancingAuthorities.Whendata
sourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingindelayedor
incorrectoperatoraction.
TheintentofRequirementR8istoprovideaccuracyinthemeasurementandcalculations
usedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
instantaneousvaluesforthetieͲlinemegawattflowvaluesbetweenBalancingAuthority
Areas.CommondatasourcerequirementsalsoapplytoinstantaneousvaluesforpseudoͲ
tiesanddynamicschedules,andcanextendtomorethantwoBalancingAuthoritiesthat
participateinallocatingsharesofagenerationresourceinsupplementaryregulation,for
example.
R8.
EachBalancingAuthorityshallagreewithanAdjacentBalancingAuthorityona
commonsourceforrespectiveTieͲLines,PseudoͲTies,andDynamicSchedulesand
shallimplementthatcommonsourcetoprovidecommoninformationtoboth
BalancingAuthoritiesforthecalculationofReportingACE.[ViolationRiskFactor:
Medium][TimeHorizon:OperationsPlanning]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page8of16
BALͲ005Ͳ1–BalancingAuthorityControl
M8. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodetermineifitagreedwithitsadjacentBalancingAuthorityona
commonsourceforthecomponentsusedinthecalculationofReportingACE.
C. Compliance
1.
ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliabilityStandards.
1.2. EvidenceRetention
Thefollowingevidenceretentionperiod(s)identifytheperiodoftimean
entityisrequiredtoretainspecificevidencetodemonstratecompliance.For
instanceswheretheevidenceretentionperiodspecifiedbelowisshorterthan
thetimesincethelastaudit,theComplianceEnforcementAuthoritymayask
anentitytoprovideotherevidencetoshowthatitwascompliantforthefullͲ
timeperiodsincethelastaudit.
Theapplicableentityshallkeepdataorevidencetoshowcomplianceas
identifiedbelowunlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
x
Theapplicableentityshallkeepdataorevidencetoshowcompliancefor
thecurrentyear,plusthreepreviouscalendaryears.
1.3. ComplianceMonitoringandAssessmentProcesses:
AsdefinedintheNERCRulesofProcedure,“ComplianceMonitoringand
AssessmentProcesses”referstotheidentificationoftheprocessesthatwill
beusedtoevaluatedataorinformationforthepurposeofassessing
performanceoroutcomeswiththeassociatedReliabilityStandard.
1.4. AdditionalComplianceInformation
None
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page9of16
Medium
Medium
R1. Operations
Planning
R2. RealͲtime
Operations
Draft#1ofStandardBALͲ005Ͳ1:July,2015
VRF
Time
Horizon
R#
Table of Compliance Elements
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
Violation Severity Levels
Page10of16
BalancingAuthority
wasusingascanrate
ofgreaterthansix
secondstoacquire
thedatanecessaryto
calculateReporting
ACE.
TheBalancing
Authorityfailedto
providethe
megawatthour
valuestoitsAdjacent
BalancingAuthorities.
Or
TheBalancing
Authorityfailedto
agreeuponatime
synchronized
commonsourcefor
hourlymegawatt
hourvalueswithits
AdjacentBalancing
Authorities
Severe VSL
Medium
R4. RealͲtime
Operations
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Medium
R3. RealͲtime
Operations
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.95%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.94%ofthe
calendaryear.
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin60
minutesofthe
beginningofan
inabilitytocalculate
ReportingACE.
Page11of16
TheBalancing
TheBalancing
TheBalancing
Authority’sfrequency Authority’sfrequency Authority’sfrequency
meteringequipment meteringequipment meteringequipment
usedforthe
usedforthe
usedforthe
calculationof
calculationof
calculationof
ReportingACEwas
ReportingACEwas ReportingACEwas
availablelessthan
availablelessthan availablelessthan
99.93%ofthe
99.94%ofthe
99.92%ofthe
calendaryearbutwas
calendaryearbut
calendaryear
availablegreaterthan wasavailablegreater
Or
orequalto99.93%of
thanorequalto
TheBalancing
thecalendaryear.
99.92%ofthe
Authority’sfrequency
calendaryear.
meteringequipment
usedforthe
TheBalancing
TheBalancing
TheBalancing
Authorityfailedto
Authorityfailedto
Authorityfailedto
notifyitsReliability
notifyitsReliability
notifyitsReliability
Coordinatorwithin Coordinatorwithin50 Coordinatorwithin
45minutesofthe
minutesofthe
55minutesofthe
beginningofan
beginningofan
beginningofan
inabilitytocalculate inabilitytocalculate inabilitytocalculate
ReportingACEbut
ReportingACEbut
ReportingACEbut
notifieditsReliability notifieditsReliability notifieditsReliability
Coordinatorinless
Coordinatorinless
Coordinatorinless
thanorequalto50
thanorequalto55
thanorequalto60
minutesfromthe
minutesfromthe
minutesfromthe
beginningofan
beginningofan
beginningofan
inabilitytocalculate inabilitytocalculate inabilitytocalculate
ReportingACE.
ReportingACE.
ReportingACE.
BALͲ005Ͳ1–BalancingAuthorityControl
Medium
Medium
Draft#1ofStandardBALͲ005Ͳ1:July,2015
R7. SameͲday
Operations
R6. Operations Medium
Assessment
R5. RealͲtime
Operations
N/A
N/A
N/A
N/A
N/A
N/A
TheBalancing
TheBalancing
TheBalancing
Authority’ssystem
Authority’ssystem
Authority’ssystem
usedforthe
usedforthe
usedforthe
calculationof
calculationof
calculationof
ReportingACEwas
ReportingACEwas
ReportingACEwas
availablelessthan
availablelessthan
availablelessthan
99.5%ofthecalendar 99.4%ofthecalendar 99.3%ofthecalendar
yearbutwas
yearbutwas
yearbutwas
availablegreater
availablegreater
availablegreaterthan
thanorequalto99.4 orequalto99.3%of thanorequalto99.2
%ofthecalendar
thecalendaryear.
%ofthecalendar
year.
year.
BALͲ005Ͳ1–BalancingAuthorityControl
Page12of16
TheBalancing
authorityfailedto
implementan
OperatingProcessto
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.2%ofthecalendar
year.
TheBalancing
Authorityfailedto
makeavailable
information
indicatingmissingor
invaliddata
associatedwith
ReportingACEtoits
operators.
calculationof
ReportingACEfailed
tohaveaminimum
accuracyof0.001Hz.
Medium
Draft#1ofStandardBALͲ005Ͳ1:July,2015
None.
E. Interpretations
None.
D. Regional Variances
R8. Operations
Planning
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
N/A
Page13of16
TheBalancing
Authorityfailedto
implementthe
commonsourceto
providecommon
informationtoboth
BalancingAuthorities.
Or
TheBalancing
Authorityfailedto
agreeupona
commonsourcefor
tieͲlines,PseudoͲties
andDynamic
Scheduleswithits
AdjacentBalancing
Authorities
identifyandmitigate
errorsaffectingthe
scanͲrateaccuracyof
datausedinthe
calculationof
ReportingACE.
Date
Action
Change Tracking
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page14of16
Standards Attachments
NOTE:Usethissectionforattachmentsorotherdocumentsthatarereferencedinthestandardaspartoftherequirements.These
shouldappearaftertheendofthestandardtemplateandbeforetheSupplementalMaterial.Iftherearenone,deletethissection.
Version
Version History
None.
F. Associated Documents
BALͲ005Ͳ1–BalancingAuthorityControl
SupplementalMaterial
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page15of16
SupplementalMaterial
Rationale
UponBoardapproval,thetextfromtherationaleboxeswillbemovedtothissection.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page16of16
Standard BAL-006-3 — Inadvertent Interchange
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiod.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft #1 of Standard BAL-006-3: July, 2015
1
Standard BAL-006-3 — Inadvertent Interchange
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft #1 of Standard BAL-006-3: July, 2015
2
Standard BAL-006-3 — Inadvertent Interchange
Introduction
1.
Title:
Inadvertent Interchange
2.
Number:
BAL-006-3
3.
Purpose:
This standard defines a process for monitoring Balancing Authorities to ensure that, over the
long term, Balancing Authority Areas do not excessively depend on other Balancing Authority
Areas in the Interconnection for meeting their demand or Interchange obligations.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
See Implementation Plan
Requirements
R1. Each Balancing Authority shall calculate and record hourly Inadvertent Interchange.
(Violation Risk Factor: Lower)
R2. Each Balancing Authority shall include all AC tie lines that connect to its Adjacent Balancing
Authority Areas in its Inadvertent Interchange account. The Balancing Authority shall take
into account interchange served by jointly owned generators. (Violation Risk Factor: Lower)
R3. Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and
Actual Net Interchange value and shall record these hourly quantities, with like values but
opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange based on
the following: (Violation Risk Factor: Lower)
R3.1. Each Balancing Authority, by the end of the next business day, shall agree with its
Adjacent Balancing Authorities to: (Violation Risk Factor: Lower)
R3.1.1 The hourly values of Net Interchange Schedule. (Violation Risk Factor: Lower)
R3.1.2 The hourly integrated megawatt-hour values of Net Actual Interchange.
(Violation Risk Factor: Lower)
R3.2. Each Balancing Authority shall use the agreed-to daily and monthly accounting data to
compile its monthly accumulated Inadvertent Interchange for the On-Peak and OffPeak hours of the month. (Violation Risk Factor: Lower)
R3.3. A Balancing Authority shall make after-the-fact corrections to the agreed-to daily and
monthly accounting data only as needed to reflect actual operating conditions (e.g. a
meter being used for control was sending bad data). Changes or corrections based on
non-reliability considerations shall not be reflected in the Balancing Authority’s
Inadvertent Interchange. After-the-fact corrections to scheduled or actual values will
not be accepted without agreement of the Adjacent Balancing Authority(ies).
(Violation Risk Factor: Lower)
R4. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual
Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following
month shall, for the purposes of dispute resolution, submit a report to their respective Regional
Reliability Organization Survey Contact. The report shall describe the nature and the cause of
the dispute as well as a process for correcting the discrepancy. (Violation Risk Factor: Lower)
C.
Measures
None specified.
Draft #1 of Standard BAL-006-3: July, 2015
3
Standard BAL-006-3 — Inadvertent Interchange
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.
These summaries shall not include any after-the-fact changes that were not agreed to
by the Source Balancing Authority, Sink Balancing Authority and all Intermediate
Balancing Authority(ies).
1.2.
Inadvertent Interchange summaries shall include at least the previous accumulation, net
accumulation for the month, and final net accumulation, for both the On-Peak and OffPeak periods.
1.3.
Each Balancing Authority shall submit its monthly summary report to its Regional
Reliability Organization Survey Contact by the 15th calendar day of the following
month.
1.4.
Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as
requested by the NERC Operating Committee to determine the Balancing Authority’s
Interchange error(s) due to equipment failures or improper scheduling operations, or
improper AGC performance.
1.5.
Each Regional Reliability Organization shall prepare a monthly Inadvertent
Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent
Interchange and all-time accumulated Inadvertent Interchange. Each Regional
Reliability Organization shall submit a monthly accounting to NERC by the 22nd day
following the end of the month being summarized.
Draft #1 of Standard BAL-006-3: July, 2015
4
N/A
The Balancing Authority failed to
record Actual Net Interchange
values that are equal but opposite
in sign to its Adjacent Balancing
Authorities.
N/A
R2.
R3.
R3.1.
Draft #1 of Standard BAL-006-3: July, 2015
N/A
Lower VSL
Violation Severity Levels
R1.
R#
2.
Moderate VSL
N/A
The Balancing Authority failed to
compute Inadvertent Interchange.
N/A
N/A
Standard BAL-006-3 — Inadvertent Interchange
Failed to take into account
interchange served by jointly
owned generators.
Failed to take into account
interchange served by jointly
owned generators.
N/A
The hourly integrated megawatthour values of Net Actual
AND
5
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
N/A
AND
OR
The Balancing Authority failed to
operate to a common Net
Interchange Schedule that is equal
but opposite to its Adjacent
Balancing Authorities.
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
Each Balancing Authority failed to
calculate and record hourly
Inadvertent Interchange.
Severe VSL
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
N/A
High VSL
N/A
N/A
N/A
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities, submitted a
report to their respective Regional
R3.1.2.
R3.2.
R3.3.
R4.
Draft #1 of Standard BAL-006-3: July, 2015
N/A
Lower VSL
R3.1.1.
R#
Moderate VSL
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities by the 15th
calendar day of the following
N/A
N/A
N/A
N/A
Standard BAL-006-3 — Inadvertent Interchange
N/A
N/A
N/A
N/A
N/A
High VSL
N/A
6
The Balancing Authority failed to
make after-the-fact corrections to
the agreed-to daily and monthly
accounting data to reflect actual
operating conditions or changes or
corrections based on non-reliability
considerations were reflected in the
Balancing Authority’s Inadvertent
Interchange.
The Balancing Authority failed to
use the agreed-to daily and
monthly accounting data to
compile its monthly accumulated
Inadvertent Interchange for the OnPeak and Off-Peak hours of the
month.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
integrated megawatt-hour values of
Net Actual Interchange.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
Interchange.
Severe VSL
Moderate VSL
month, failed to submit a report to
their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute as well as a
process for correcting the
discrepancy.
Lower VSL
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute but failed
to provide a process for correcting
the discrepancy.
Draft #1 of Standard BAL-006-3: July, 2015
R#
Standard BAL-006-3 — Inadvertent Interchange
High VSL
Severe VSL
7
Standard BAL-006-3 — Inadvertent Interchange
E.
Regional Differences
1.
Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March
25, 2004includes SPP effective May 1, 2006.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
April 6, 2006
Added following to “Effective Date:” This
standard will expire for one year beyond the
effective date or when replaced by a new version
of BAL-006, whichever comes first.
Errata
2
November 5, 2009
Added approved VRFs and VSLs to document.
Revision
Removed MISO from list of entities with an
Inadvertent Interchange Accounting Waiver
(Project 2009-18).
2
November 5, 2009
Approved by the Board of Trustees
2
January 6, 2011
Approved by FERC
Draft #1 of Standard BAL-006-3: July, 2015
8
Standard BAL-006-32 — Inadvertent Interchange
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiod.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft #1 of Standard BAL-006-3: July, 2015
1
Standard BAL-006-32 — Inadvertent Interchange
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft #1 of Standard BAL-006-3: July, 2015
2
Standard BAL-006-32 — Inadvertent Interchange
Introduction
1.
Title:
Inadvertent Interchange
2.
Number:
BAL-006-32
3.
Purpose:
This standard defines a process for monitoring Balancing Authorities to ensure that, over the
long term, Balancing Authority Areas do not excessively depend on other Balancing Authority
Areas in the Interconnection for meeting their demand or Interchange obligations.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
See Implementation Plan
Requirements
R1. Each Balancing Authority shall calculate and record hourly Inadvertent Interchange.
(Violation Risk Factor: Lower)
R2. Each Balancing Authority shall include all AC tie lines that connect to its Adjacent Balancing
Authority Areas in its Inadvertent Interchange account. The Balancing Authority shall take
into account interchange served by jointly owned generators. (Violation Risk Factor: Lower)
R3. Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection
points are equipped with common megawatt-hour meters, with readings provided hourly to the
control centers of Adjacent Balancing Authorities. (Violation Risk Factor: Lower)
R4.R3. Adjacent Balancing Authority Areas shall operate to a common Net Interchange
Schedule and Actual Net Interchange value and shall record these hourly quantities, with like
values but opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange
based on the following: (Violation Risk Factor: Lower)
R4.1.R3.1. Each Balancing Authority, by the end of the next business day, shall agree with
its Adjacent Balancing Authorities to: (Violation Risk Factor: Lower)
R3.1.1 The hourly values of Net Interchange Schedule. (Violation Risk Factor: Lower)
R3.1.2 The hourly integrated megawatt-hour values of Net Actual Interchange.
(Violation Risk Factor: Lower)
R4.2.R3.2. Each Balancing Authority shall use the agreed-to daily and monthly accounting
data to compile its monthly accumulated Inadvertent Interchange for the On-Peak and
Off-Peak hours of the month. (Violation Risk Factor: Lower)
R4.3.R3.3. A Balancing Authority shall make after-the-fact corrections to the agreed-to daily
and monthly accounting data only as needed to reflect actual operating conditions (e.g.
a meter being used for control was sending bad data). Changes or corrections based on
non-reliability considerations shall not be reflected in the Balancing Authority’s
Inadvertent Interchange. After-the-fact corrections to scheduled or actual values will
not be accepted without agreement of the Adjacent Balancing Authority(ies).
(Violation Risk Factor: Lower)
R5.R4. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net
Actual Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the
following month shall, for the purposes of dispute resolution, submit a report to their
respective Regional Reliability Organization Survey Contact. The report shall describe the
Draft #1 of Standard BAL-006-3: July, 2015
3
Standard BAL-006-32 — Inadvertent Interchange
nature and the cause of the dispute as well as a process for correcting the discrepancy.
(Violation Risk Factor: Lower)
C.
Measures
None specified.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.
These summaries shall not include any after-the-fact changes that were not agreed to
by the Source Balancing Authority, Sink Balancing Authority and all Intermediate
Balancing Authority(ies).
1.2.
Inadvertent Interchange summaries shall include at least the previous accumulation, net
accumulation for the month, and final net accumulation, for both the On-Peak and OffPeak periods.
1.3.
Each Balancing Authority shall submit its monthly summary report to its Regional
Reliability Organization Survey Contact by the 15th calendar day of the following
month.
1.4.
Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as
requested by the NERC Operating Committee to determine the Balancing Authority’s
Interchange error(s) due to equipment failures or improper scheduling operations, or
improper AGC performance.
1.5.
Each Regional Reliability Organization shall prepare a monthly Inadvertent
Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent
Interchange and all-time accumulated Inadvertent Interchange. Each Regional
Reliability Organization shall submit a monthly accounting to NERC by the 22nd day
following the end of the month being summarized.
Draft #1 of Standard BAL-006-3: July, 2015
4
N/A
N/A
The Balancing Authority failed to
record Actual Net Interchange
values that are equal but opposite
in sign to its Adjacent Balancing
Authorities.
N/A
R2.
R3.
R34.
R34.1.
Draft #1 of Standard BAL-006-3: July, 2015
N/A
Lower VSL
Violation Severity Levels
R1.
R#
2.
N/A
The Balancing Authority failed to
compute Inadvertent Interchange.
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-32 — Inadvertent Interchange
Failed to take into account
interchange served by jointly
owned generators.
Failed to take into account
interchange served by jointly
owned generators.
N/A
The Balancing Authority failed to
operate to a common Net
Interchange Schedule that is equal
but opposite to its Adjacent
Balancing Authorities.
5
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
N/A
The Balancing Authority failed to
ensure all of its Balancing
Authority Area interconnection
points are equipped with common
megawatt-hour meters, with
readings provided hourly to the
control centers of Adjacent
Balancing Authorities.
AND
OR
N/A
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
Each Balancing Authority failed to
calculate and record hourly
Inadvertent Interchange.
Severe VSL
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
N/A
High VSL
N/A
N/A
N/A
R34.1.
2.
R34.2.
R34.3.
Lower VSL
Draft #1 of Standard BAL-006-3: July, 2015
N/A
R34.1.
1.
R#
N/A
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-32 — Inadvertent Interchange
N/A
N/A
N/A
N/A
High VSL
6
The Balancing Authority failed to
make after-the-fact corrections to
the agreed-to daily and monthly
accounting data to reflect actual
operating conditions or changes or
corrections based on non-reliability
considerations were reflected in the
Balancing Authority’s Inadvertent
The Balancing Authority failed to
use the agreed-to daily and
monthly accounting data to
compile its monthly accumulated
Inadvertent Interchange for the OnPeak and Off-Peak hours of the
month.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
integrated megawatt-hour values of
Net Actual Interchange.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
The hourly integrated megawatthour values of Net Actual
Interchange.
AND
Schedule.
Severe VSL
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities, submitted a
report to their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute but failed
to provide a process for correcting
the discrepancy.
Lower VSL
Draft #1 of Standard BAL-006-3: July, 2015
R45.
R#
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities by the 15th
calendar day of the following
month, failed to submit a report to
their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute as well as a
process for correcting the
discrepancy.
Moderate VSL
Standard BAL-006-32 — Inadvertent Interchange
N/A
High VSL
N/A
Interchange.
Severe VSL
7
Standard BAL-006-32 — Inadvertent Interchange
E.
Regional Differences
1.
Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March
25, 2004includes SPP effective May 1, 2006.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
April 6, 2006
Added following to “Effective Date:” This
standard will expire for one year beyond the
effective date or when replaced by a new version
of BAL-006, whichever comes first.
Errata
2
November 5, 2009
Added approved VRFs and VSLs to document.
Revision
Removed MISO from list of entities with an
Inadvertent Interchange Accounting Waiver
(Project 2009-18).
2
November 5, 2009
Approved by the Board of Trustees
2
January 6, 2011
Approved by FERC
Draft #1 of Standard BAL-006-3: July, 2015
8
FAC-001-3 — Facility Interconnection Requirements
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 1 of 11
FAC-001-3 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 2 of 11
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
4.1.3
5.
Load Serving Entities
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 3 of 11
FAC-001-3 — Facility Interconnection Requirements
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
R5. Each Transmission Owner with Transmission Facilities operating in an Interconnection
shall confirm that each Transmission Facility is within a Balancing Authority Area’s
metered boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term
Planning]
M5. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R5.
R6. Each Generator Owner with generation Facilities operating in an Interconnection shall
confirm that each generation Facility is within a Balancing Authority Area’s metered
boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term Planning]
M6. Each Generator Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R6.
R7. Each Load-Serving Entity with Load operating in an Interconnection shall confirm that
each Load is within a Balancing Authority Area’s metered boundaries. [Violation Risk
Factor: Medium] [Time Horizon: Long-Term Planning]
M7. Each applicable Load Serving Entity shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R7.
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 4 of 11
FAC-001-3 — Facility Interconnection Requirements
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Transmission Owner and applicable Generator Owner shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 5 of 11
Lower
Long-term
Planning
R1
Draft#1ofStandardFACͲ001Ͳ3:July,2015
VRF
Time
Horizon
R#
N/A
Table of Compliance Elements
Lower VSL
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 6 of 11
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
Draft#1ofStandardFACͲ001Ͳ3:July,2015
R2
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 7 of 11
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
N/A
Medium N/A
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Long-term
Planning
R5
N/A
N/A
Lower
Long-term
Planning
R4
N/A
Lower
Long-term
Planning
R3
N/A
FAC-001-3 — Facility Interconnection Requirements
N/A
The applicable
Generator Owner
addressed either R4,
Part 4.1 or Part 4.2 in
its Facility
interconnection
requirements, but did
not address both.
The Transmission
Owner addressed
either R3, Part 3.1 or
Part 3.2 in its Facility
interconnection
requirements, but did
not address both.
Page 8 of 11
The Transmission
Operator with
Transmission Facilities
operating in an
Interconnection failed
to ensure that those
Transmission Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The applicable
Generator Owner
addressed neither R4,
Part 4.1 nor Part 4.2 in
its Facility
interconnection
requirements.
The Transmission
Owner addressed
neither R3, Part 3.1 nor
Part 3.2 in its Facility
interconnection
requirements.
Long-term
Planning
R7
N/A
N/A
Medium N/A
Medium N/A
Draft#1ofStandardFACͲ001Ͳ3:July,2015
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
Long-term
Planning
R6
FAC-001-3 — Facility Interconnection Requirements
N/A
N/A
Page 9 of 11
The Generation
Operator with
generation Facilities
operating in an
Interconnection failed
to ensure that those
generation Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The Load-Serving
Entity with Load
operating in an
Interconnection failed
to ensure that those
Loads were included
within metered
boundaries of a
Balancing Authority
Area.
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 10 of 11
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 11 of 11
FAC-001-23 — Facility Interconnection Requirements
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 1 of 11
FAC-001-23 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 2 of 11
FAC-001-23 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-23
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
4.1.3
5.
Load Serving Entities
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 3 of 11
FAC-001-23 — Facility Interconnection Requirements
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
R5. Each Transmission Owner with Transmission Facilities operating in an Interconnection
shall confirm that each Transmission Facility is within a Balancing Authority Area’s
metered boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term
Planning]
M5. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R5.
R6. Each Generator Owner with generation Facilities operating in an Interconnection shall
confirm that each generation Facility is within a Balancing Authority Area’s metered
boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term Planning]
M6. Each Generator Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R6.
R7. Each Load-Serving Entity with Load operating in an Interconnection shall confirm that
each Load is within a Balancing Authority Area’s metered boundaries. [Violation Risk
Factor: Medium] [Time Horizon: Long-Term Planning]
M7. Each applicable Load Serving Entity shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R7.
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 4 of 11
FAC-001-23 — Facility Interconnection Requirements
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Transmission Owner and applicable Generator Owner shall keep data or
evidence to show compliance as identified below unless directed by its CEA to
retain specific evidence for a longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Page 5 of 11
Lower
Long-term
Planning
R1
Draft#1ofStandardFACͲ001Ͳ3:July,2015
VRF
Time
Horizon
R#
N/A
Table of Compliance Elements
Lower VSL
FAC-001-23 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 6 of 11
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
Draft#1ofStandardFACͲ001Ͳ3:July,2015
R2
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
FAC-001-23 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 7 of 11
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
N/A
Medium N/A
Draft#1ofStandardFACͲ001Ͳ3:July,2015
Long-term
Planning
R5
N/A
N/A
Lower
Long-term
Planning
R4
N/A
Lower
Long-term
Planning
R3
N/A
FAC-001-23 — Facility Interconnection Requirements
N/A
The applicable
Generator Owner
addressed either R4,
Part 4.1 or Part 4.2 in
its Facility
interconnection
requirements, but did
not address both.
The Transmission
Owner addressed
either R3, Part 3.1 or
Part 3.2 in its Facility
interconnection
requirements, but did
not address both.
Page 8 of 11
The Transmission
Operator with
Transmission Facilities
operating in an
Interconnection failed
to ensure that those
Transmission Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The applicable
Generator Owner
addressed neither R4,
Part 4.1 nor Part 4.2 in
its Facility
interconnection
requirements.
The Transmission
Owner addressed
neither R3, Part 3.1 nor
Part 3.2 in its Facility
interconnection
requirements.
Medium
Long-term
Planning
R7
Draft#1ofStandardFACͲ001Ͳ3:July,2015
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
Medium
Long-term
Planning
R6
N/A
N/A
N/A
N/A
FAC-001-23 — Facility Interconnection Requirements
N/A
N/A
Page 9 of 11
The Generation
Operator with
generation Facilities
operating in an
Interconnection failed
to ensure that those
generation Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The Load-Serving
Entity with Load
operating in an
Interconnection failed
to ensure that those
Loads were included
within metered
boundaries of a
Balancing Authority
Area.
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 10 of 11
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 11 of 11
Implementation Plan
Reliability Standard BAL-005-1
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
BAL-005-1 – Balancing Authority Controls
Requested Retirement
x
BAL-005-0.2b – Automatic Generation Control
Prerequisite Approval
x
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers
across all Tie Lines, including PseudoǦTies, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (IME): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (IATEC): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of IATEC shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
x Lmax is the maximum value allowed for IATEC set by each BA between 0.2*|Bi| and
L10, 0.2*|Bi|≤ Lmax ≤ L10 .
x
L10 ൌ ͳǤͷ כȜଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ .
x
10 is a constant derived from the targeted frequency bound. It is the targeted rootmean-square (RMS) value of ten-minute average frequency
enc error based on
frequency performance over a given year. The bound, 10, is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - Bi * ΔTE/6)
IIactual is the hourly Inadvertent Interchange for the last hour.
ΔTE is the hourly change in system Time Error as distributed by the Interconnection
time monitor,where: ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)
TDadj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TEoffset is 0.000 or +0.020 or -0.020.
PIIaccum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
x
x
x
x
x
x
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
BAL-005-1 – Balancing Authority Control
July 2015
PIIࢎ࢛࢘࢟
2
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) – IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) – IME + IATEC
Where:
x NIA
=
Actual Net Interchange.
x
NIS
=
Scheduled Net Interchange.
x
B
=
Frequency Bias Setting.
x
FA
=
Actual Frequency.
x
FS
=
Scheduled Frequency.
x
IME
=
Interchange Meter Error.
x
IATEC
=
Automatic Time Error Correction.
All NERC Interconnections with multiple Balancing Authority Areas operate using
the principles of Tie-line Bias (TLB) Control and require the use of an ACE
equation similar to the Reporting ACE defined above. Any modification(s) to this
specified Reporting ACE equation that is(are) implemented for all BAAs on an
Interconnection and is(are) consistent with the following four principles of Tie
Line Bias control will provide a valid alternative to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency FS for all BAAs at all times; and,
BAL-005-1 – Balancing Authority Control
July 2015
3
4. Excludes metering or computational errors. (The inclusion and use of the IME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC): Centrally located equipment Equipment that
automatically adjusts resources generation in a Balancing Authority Area from a central
location to help maintain the Reporting ACE of a Balancing Authority’s Area within the
bounds required under the NERC Reliability Standardsinterchange schedule plus
Frequency Bias. AGC may also accommodate automatic inadvertent payback and time
error correction. Resources utilized under AGC may include, but not be limited to,
conventional generation, variable energy resources, storage devices and loads acting as
resources, such as Demand Response.
Applicable Entities
x
Balancing Authority
Applicable Facilities
x
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-005-1 will implemented concurrently with FAC-001-3, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
BAL-005-1 and associated definitions shall become effective on the first day of the first calendar
quarter that is twelve months after the date that this standard is approved by applicable
BAL-005-1 – Balancing Authority Control
July 2015
4
regulatory authorities or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval
by an applicable governmental authority is not required, the standard shall become effective on
the first day of the first calendar quarter that is twelve months after the date the standard is
adopted by the NERC Board of Trustees’, or as otherwise provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Reporting ACE and Automatic Generation Control should be retired
at midnight of the day immediately prior to the effective date of BAL-005-1, in the jurisdiction
in which the new standard is becoming effective.
BAL-005-1 – Balancing Authority Control
July 2015
5
Implementation Plan
Reliability Standard BAL-006-3
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
BAL-006-3 – Inadvertent Interchange
Requested Retirement
x
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-3 will be implemented concurrently with BAL-005-1, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
BAL-006-3 shall become effective on the effective date of BAL-005-1.
Retirements
BAL-006-2 (Inadvertent Interchange) shall be retired immediately prior to the Effective Date of
BAL-006-3 (Inadvertent Interchange) in the particular jurisdiction in which the revised
standard is becoming effective.
Implementation Plan
Reliability Standard FAC-001-3
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
FAC-001-3 – Facility Interconnection Requirements
Requested Retirement
x
FAC-001-2 – Facility Interconnection Requirements
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
Background
Reliability Standard FAC-001-3 addresses Facility Interconnection Requirements, which ensure
the avoidance of adverse impacts on the reliability of the Bulk Electric System by requiring
Transmission Owners and applicable Generator Owners to document and make Facility
interconnection requirements available so that entities seeking to interconnect will have
necessary information. Reliability Standard FAC-001-3 and associated Implementation Plan was
developed in conjunction with BAL-005-1 (Balancing Authority Controls) to ensure that entities
with facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented concurrently with BAL-005-1, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
FAC-001-3 shall become effective on the effective date of BAL-005-1.
Retirements
FAC-001-2 (Facility Interconnection Requirements) shall be retired immediately prior to the
Effective Date of FAC-001-3 (Facility Interconnection Requirements) in the particular
jurisdiction in which the revised standard is becoming effective.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
July2015
2
BALͲ005Ͳ1–BalancingAuthorityControl
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithparallelballot
August/September
2015
Finalballot
October2015
NERCBoardadoption
November2015
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page1of16
BALͲ005Ͳ1–BalancingAuthorityControl
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:
AutomaticGenerationControl(AGC):Centrally located equipment Equipment that
automatically adjusts resources generation in a Balancing Authority Area from a central
location to help maintain the Reporting ACE in that of a Balancing Authority’s Area within
the bounds required by applicable NERC Reliability Standardsinterchange schedule plus
Frequency Bias. AGC may also accommodate automatic inadvertent payback and time error
correction. ResourcesutilizedunderAGCmayinclude,butarenotlimitedto,conventional
generation,variableenergyresources,storagedevicesandloadsactingasresources(suchas
DemandResponse).
ActualFrequency(FA):TheInterconnectionfrequencymeasuredinHertz(Hz).
ActualNetInterchange(NIA):ThealgebraicsumofactualmegawatttransfersacrossallTie
Lines,includingPseudoͲTies,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection.ActualmegawatttransfersonasynchronousDCtielinesthataredirectly
connectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
ScheduledNetInterchange(NIS):Thealgebraicsumofallscheduledmegawatttransfers,
includingDynamicSchedules,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection,includingtheeffectofscheduledramps.Scheduledmegawatttransfers
onasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionareexcludedfrom
ScheduledNetInterchange.
InterchangeMeterError(IME):Aterm,normallyzero,usedintheReportingACEcalculationto
compensatefordataorequipmenterrorsaffectinganyothercomponentsoftheReportingACE
calculation.
AutomaticTimeErrorCorrection(IATEC):TheadditionofacomponenttotheACEequationfor
theWesternInterconnectionthatmodifiesthecontrolpointforthepurposeofcontinuously
payingbackPrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.Automatic
TimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
whenoperatinginAutomaticTimeErrorCorrectionMode.
TheabsolutevalueofIATECshallnotexceedLmax.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page2of16
BALͲ005Ͳ1–BalancingAuthorityControl
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|Bi|andL10,
0.2*|Bi|чLmaxчL10.
x
x
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare
(RMS)valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragiven
year.Thebound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
x
x
Y=Bi/BS.
H=Numberofhoursusedtopaybackprimaryinadvertentinterchangeenergy.Thevalue
ofHissetto3.
x
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
x
x
x
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲBi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontime
monitor,where: ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontime
monitorcontrolcenterclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲ
Peakaccumulationaccountingisrequired,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
ReportingACE:ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError
(ACE)measuredinMWincludesthedifferencebetweentheBalancingAuthorityArea’sActual
NetInterchangeanditsScheduledNetInterchange,plusitsFrequencyBiasSettingobligation,
pluscorrectionforanyknownmetererror.IntheWesternInterconnection,ReportingACE
includesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
x NIA
=
ActualNetInterchange.
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page3of16
BALͲ005Ͳ1–BalancingAuthorityControl
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
x IATEC
=
AutomaticTimeErrorCorrection.
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartotheReporting
ACEdefinedabove.Anymodification(s)tothisspecifiedReportingACEequationthatis(are)
implementedforallBAAsonanInterconnectionandis(are)consistentwiththefollowingfour
principlesofTieLineBiascontrolwillprovideavalidalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofall
BAAs’generation,load,andlossisthesameastotalInterconnectiongeneration,load,
andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimes
andthesumofallBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEterm
correctsforknownmeteringorcomputationalerrors.)
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page4of16
BALͲ005Ͳ1–BalancingAuthorityControl
Whenthisstandardhasreceivedballotapproval,thetextboxeswillbemovedtothe
SupplementalMaterialSectionofthestandard.
A. Introduction
1.
Title:
BalancingAuthorityControl
2.
Number:
BALͲ005Ͳ1
3.
Purpose: Thisstandardestablishesrequirementsforacquiringdatanecessaryto
calculateReportingAreaControlError(ReportingACE).Thestandardalsospecifiesa
minimumperiodicity,accuracy,andavailabilityrequirementforacquisitionofthe
dataandforprovidingtheinformationtotheSystemOperator.
4.
Applicability:
4.1. FunctionalEntities:
4.1.1. BalancingAuthority
4.2. Facilities:
4.2.1. N/A
EffectiveDate: See Implementation Plan
B. Requirements and Measures
RationaleforRequirementR1:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedata(meaning
datafromthesamesource)iscriticaltocalculatingReportingACEthatisconsistent
betweenBalancingAuthorities.Whendatasourcesarenotcommon,confusioncanbe
createdbetweenBAsresultingindelayedorincorrectoperatoraction.
TheintentofRequirementR1istoprovideaccuracyinthemeasurementsand
calculationsusedinReportingACE,hourlyinadvertentenergy,andFrequencyResponse
measurements.Itspecifiestheneedforcommonmeteringpointsforinstantaneousand
hourlyintegratedvaluesforthetielinemegawattflowvaluesbetweenBalancing
AuthorityAreas.Commondatasourcerequirementsalsoapplywhenmorethantwo
BalancingAuthoritiesparticipateinallocatingsharesofagenerationresourceorin
supplementaryregulation,forexample.
R1.
EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,andDynamic
SchedulewithanAdjacentBalancingAuthorityisequippedwithamutuallyagreedͲ
upontimesynchronizedcommonsourcetodeterminehourlymegawattͲhourvalues.
[ViolationRiskFactor:Medium][TimeHorizon:OperationsPlanning]
1.1. ThesevaluesshallbeexchangedbetweenAdjacentBalancingAuthorities.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page5of16
BALͲ005Ͳ1–BalancingAuthorityControl
M1. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodetermineiftheBalancingAuthorityanditsadjacentBalancing
Authorityhaveagreeduponatimesynchronizedcommonsourcetodetermine
megawattͲhourvalues.
RationaleforRequirementR2:RealͲtimeoperationofaBalancingAuthorityrequires
realͲtimeinformation.AsufficientscanrateiskeytoanOperator’strustinrealͲtime
information.Withoutasufficientscanrate,anoperatormayquestiontheaccuracyof
dataduringeventswhichwoulddegradetheoperator’sabilitytomaintainreliability.
R2.
TheBalancingAuthorityshalluseascanrateofnomorethansixsecondsinacquiring
datanecessarytocalculateReportingACE.[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]
M2. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthedata
necessarytocalculateReportingACEwasscannedatarateofnomorethansix
seconds.Acceptableevidencemayincludehistoricaldata,datedarchivefiles;ordata
fromotherdatabases,spreadsheets,ordisplaysthatdemonstratecompliance.
RationaleforRequirementR3:TheRCisresponsibleforcoordinatingthereliabilityof
bulkelectricsystemsformemberBA’s.WhenaBAisunabletocalculateitsACEforan
extendedperiodoftime,thisinformationmustbecommunicatedtotheRCsothatthe
RChassufficientknowledgeofsystemconditionstoassessanyunintendedreliability
consequencesthatmayoccuronthewidearea.
R3.
ABalancingAuthoritythatisunabletocalculateReportingACEformorethan30Ͳ
consecutiveminutesshallnotifyitsReliabilityCoordinatorwithin45minutesofthe
beginningofaninabilitytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M3. EachBalancingAuthoritywillhavedatedrecordstoshowwhenitwasunableto
calculateReportingACEformorethan30consecutiveminutesandthatitnotifiedits
ReliabilityCoordinatorwithin45minutesofthebeginningofaninabilitytocalculate
ReportingACE.Suchevidencemayinclude,butisnotlimitedto,datedvoice
recordings,operatinglogs,orothercommunicationdocumentation.
RationaleforRequirementR4:Frequencyisthebasicmeasurementforinterconnection
health,andacriticalcomponentforcalculatingReportingACE.Withoutsufficient
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page6of16
BALͲ005Ͳ1–BalancingAuthorityControl
availablefrequencydatatheBAoperatorwilllacksituationalawarenessandwillbe
unabletomakecorrectdecisionswhenmaintainingreliability.
R4.
EachBalancingAuthorityshallusefrequencymeteringequipmentforthecalculation
ofReportingACE:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
4.1. thatisavailableaminimumof99.95%foreachcalendaryear;and,
4.2. withaminimumaccuracyof0.001Hz.
M4. TheBalancingAuthorityshallhaveevidencesuchasdateddocumentsorother
evidenceinhardcopyorelectronicformatshowingthefrequencymetering
equipmentusedforthecalculationofReportingACEhadaminimumavailabilityof
99.95%foreachcalendaryearandhadaminimumaccuracyof0.001Hzto
demonstratecompliancewithRequirementR4.
RationaleforRequirementR5:SystemoperatorsutilizeReportingACEasaprimary
metrictodetermineoperatingactionsorinstructions.WhendatainputsintotheACE
calculationareincorrect,theoperatorshouldbemadeawarethroughvisualdisplay.
Whenanoperatorquestionsthevalidityofdata,actionsaredelayedandtheprobability
ofadverseeventsoccurringcanincrease.
R5.
TheBalancingAuthorityshallmakeavailabletotheoperatorinformationassociated
withReportingACEincluding,butnotlimitedto,qualityflagsindicatingmissingor
invaliddata.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtimeOperations]
M5. EachBalancingAuthorityAreashallhaveevidencesuchasagraphicaldisplayordated
alarmlogthatprovidesindicationofdatavalidityfortherealͲtimeReportingACE
basedonboththecalculatedresultandalloftheassociatedinputstherein.
RationaleforRequirementR6:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthatReportingACE
besufficientlyavailabletoassurereliability.
R6.
EachBalancingAuthority’ssystemusedtocalculateReportingACEshallbeavailablea
minimumof99.5%ofeachcalendaryear.[ViolationRiskFactor:Medium][Time
Horizon:OperationsAssessment]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page7of16
BALͲ005Ͳ1–BalancingAuthorityControl
M6. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
systemnecessarytocalculateReportingACEhasaminimumavailabilityof99.5%for
eachcalendaryear.Acceptableevidencemayincludehistoricaldata,datedarchive
files;ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR7:ReportingACEisameasureoftheBA’sreliability
performanceforBALͲ001,andBALͲ002.Withoutaprocesstoaddresspersistenterrorsin
theACEcalculation,theoperatorcanlosetrustinthevalidityofReportingACEresulting
indelayedorincorrectdecisionsregardingthereliabilityofthebulkelectricsystem.
R7.
EachBalancingAuthoritythatiswithinamultipleBalancingAuthorityInterconnection
shallimplementanOperatingProcesstoidentifyandmitigateerrorsaffectingthe
scanͲrateaccuracyofdatausedinthecalculationofReportingACEforeachBalancing
AuthorityArea.[ViolationRiskFactor:Medium][TimeHorizon:SameͲdayOperations
]
M7. EachBalancingAuthorityshallhaveacurrentOperatingProcessmeetingthe
provisionsofRequirementR7andevidencetoshowthattheprocesswas
implemented,suchasdatedcommunicationsorincorporationinSystemOperator
taskverification.
RationaleforRequirementR8:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedataiscriticalto
calculatingReportingACEthatisconsistentbetweenBalancingAuthorities.Whendata
sourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingindelayedor
incorrectoperatoraction.
TheintentofRequirementR8istoprovideaccuracyinthemeasurementandcalculations
usedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
instantaneousvaluesforthetieͲlinemegawattflowvaluesbetweenBalancingAuthority
Areas.CommondatasourcerequirementsalsoapplytoinstantaneousvaluesforpseudoͲ
tiesanddynamicschedules,andcanextendtomorethantwoBalancingAuthoritiesthat
participateinallocatingsharesofagenerationresourceinsupplementaryregulation,for
example.
R8.
EachBalancingAuthorityshallagreewithanAdjacentBalancingAuthorityona
commonsourceforrespectiveTieͲLines,PseudoͲTies,andDynamicSchedulesand
shallimplementthatcommonsourcetoprovidecommoninformationtoboth
BalancingAuthoritiesforthecalculationofReportingACE.[ViolationRiskFactor:
Medium][TimeHorizon:OperationsPlanning]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page8of16
BALͲ005Ͳ1–BalancingAuthorityControl
M8. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodetermineifitagreedwithitsadjacentBalancingAuthorityona
commonsourceforthecomponentsusedinthecalculationofReportingACE.
C. Compliance
1.
ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliabilityStandards.
1.2. EvidenceRetention
Thefollowingevidenceretentionperiod(s)identifytheperiodoftimean
entityisrequiredtoretainspecificevidencetodemonstratecompliance.For
instanceswheretheevidenceretentionperiodspecifiedbelowisshorterthan
thetimesincethelastaudit,theComplianceEnforcementAuthoritymayask
anentitytoprovideotherevidencetoshowthatitwascompliantforthefullͲ
timeperiodsincethelastaudit.
Theapplicableentityshallkeepdataorevidencetoshowcomplianceas
identifiedbelowunlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
x
Theapplicableentityshallkeepdataorevidencetoshowcompliancefor
thecurrentyear,plusthreepreviouscalendaryears.
1.3. ComplianceMonitoringandAssessmentProcesses:
AsdefinedintheNERCRulesofProcedure,“ComplianceMonitoringand
AssessmentProcesses”referstotheidentificationoftheprocessesthatwill
beusedtoevaluatedataorinformationforthepurposeofassessing
performanceoroutcomeswiththeassociatedReliabilityStandard.
1.4. AdditionalComplianceInformation
None
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page9of16
Medium
Medium
R1. Operations
Planning
R2. RealͲtime
Operations
Draft#1ofStandardBALͲ005Ͳ1:July,2015
VRF
Time
Horizon
R#
Table of Compliance Elements
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
Violation Severity Levels
Page10of16
BalancingAuthority
wasusingascanrate
ofgreaterthansix
secondstoacquire
thedatanecessaryto
calculateReporting
ACE.
TheBalancing
Authorityfailedto
providethe
megawatthour
valuestoitsAdjacent
BalancingAuthorities.
Or
TheBalancing
Authorityfailedto
agreeuponatime
synchronized
commonsourcefor
hourlymegawatt
hourvalueswithits
AdjacentBalancing
Authorities
Severe VSL
Medium
R4. RealͲtime
Operations
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Medium
R3. RealͲtime
Operations
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.95%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.94%ofthe
calendaryear.
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin60
minutesofthe
beginningofan
inabilitytocalculate
ReportingACE.
Page11of16
TheBalancing
TheBalancing
TheBalancing
Authority’sfrequency Authority’sfrequency Authority’sfrequency
meteringequipment meteringequipment meteringequipment
usedforthe
usedforthe
usedforthe
calculationof
calculationof
calculationof
ReportingACEwas
ReportingACEwas ReportingACEwas
availablelessthan
availablelessthan availablelessthan
99.93%ofthe
99.94%ofthe
99.92%ofthe
calendaryearbutwas
calendaryearbut
calendaryear
availablegreaterthan wasavailablegreater
Or
orequalto99.93%of
thanorequalto
TheBalancing
thecalendaryear.
99.92%ofthe
Authority’sfrequency
calendaryear.
meteringequipment
usedforthe
TheBalancing
TheBalancing
TheBalancing
Authorityfailedto
Authorityfailedto
Authorityfailedto
notifyitsReliability
notifyitsReliability
notifyitsReliability
Coordinatorwithin Coordinatorwithin50 Coordinatorwithin
45minutesofthe
minutesofthe
55minutesofthe
beginningofan
beginningofan
beginningofan
inabilitytocalculate inabilitytocalculate inabilitytocalculate
ReportingACEbut
ReportingACEbut
ReportingACEbut
notifieditsReliability notifieditsReliability notifieditsReliability
Coordinatorinless
Coordinatorinless
Coordinatorinless
thanorequalto50
thanorequalto55
thanorequalto60
minutesfromthe
minutesfromthe
minutesfromthe
beginningofan
beginningofan
beginningofan
inabilitytocalculate inabilitytocalculate inabilitytocalculate
ReportingACE.
ReportingACE.
ReportingACE.
BALͲ005Ͳ1–BalancingAuthorityControl
Medium
Medium
Draft#1ofStandardBALͲ005Ͳ1:July,2015
R7. SameͲday
Operations
R6. Operations Medium
Assessment
R5. RealͲtime
Operations
N/A
N/A
N/A
N/A
N/A
N/A
TheBalancing
TheBalancing
TheBalancing
Authority’ssystem
Authority’ssystem
Authority’ssystem
usedforthe
usedforthe
usedforthe
calculationof
calculationof
calculationof
ReportingACEwas
ReportingACEwas
ReportingACEwas
availablelessthan
availablelessthan
availablelessthan
99.5%ofthecalendar 99.4%ofthecalendar 99.3%ofthecalendar
yearbutwas
yearbutwas
yearbutwas
availablegreater
availablegreater
availablegreaterthan
thanorequalto99.4 orequalto99.3%of thanorequalto99.2
%ofthecalendar
thecalendaryear.
%ofthecalendar
year.
year.
BALͲ005Ͳ1–BalancingAuthorityControl
Page12of16
TheBalancing
authorityfailedto
implementan
OperatingProcessto
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.2%ofthecalendar
year.
TheBalancing
Authorityfailedto
makeavailable
information
indicatingmissingor
invaliddata
associatedwith
ReportingACEtoits
operators.
calculationof
ReportingACEfailed
tohaveaminimum
accuracyof0.001Hz.
Medium
Draft#1ofStandardBALͲ005Ͳ1:July,2015
None.
E. Interpretations
None.
D. Regional Variances
R8. Operations
Planning
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
N/A
Page13of16
TheBalancing
Authorityfailedto
implementthe
commonsourceto
providecommon
informationtoboth
BalancingAuthorities.
Or
TheBalancing
Authorityfailedto
agreeupona
commonsourcefor
tieͲlines,PseudoͲties
andDynamic
Scheduleswithits
AdjacentBalancing
Authorities
identifyandmitigate
errorsaffectingthe
scanͲrateaccuracyof
datausedinthe
calculationof
ReportingACE.
Date
Action
Change Tracking
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page14of16
Standards Attachments
NOTE:Usethissectionforattachmentsorotherdocumentsthatarereferencedinthestandardaspartoftherequirements.These
shouldappearaftertheendofthestandardtemplateandbeforetheSupplementalMaterial.Iftherearenone,deletethissection.
Version
Version History
None.
F. Associated Documents
BALͲ005Ͳ1–BalancingAuthorityControl
SupplementalMaterial
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page15of16
SupplementalMaterial
Rationale
UponBoardapproval,thetextfromtherationaleboxeswillbemovedtothissection.
Draft#1ofStandardBALͲ005Ͳ1:July,2015
Page16of16
BALͲ005Ͳ0.2bR5
BALͲ005Ͳ0.2bR4
BALͲ005Ͳ0.2bR3
BALͲ005Ͳ0.2bR2
BALͲ005Ͳ1R1
Requirementin
ApprovedStandard
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Thisrequirementdoesnotprovidefornecessaryinformation
ThisRequirementhasbeen movedintoFACͲ concerningthecalculationofReportingACE.Therequirement
001Ͳ2RequirementR5,R6andR7
providesforinformationnecessarywhenconnectingtotheelectric
system.
ThisrequirementwasretiredaspartoftheoriginalParagraph81
Retired
project.ItsretirementwasapprovedbyFERCeffectiveJanuary21,
2014.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR1and
RequirementR8.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR1and
RequirementR8.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR1and
RequirementR8.
Transition of BAL-005-0.2b to BAL-005-1
Project 2010-14.2.1 Mapping Document
BALͲ005Ͳ0.2bR9
BALͲ005Ͳ0.2bR8
BALͲ005Ͳ0.2bR7
BALͲ005Ͳ0.2bR6
Requirementin
ApprovedStandard
2
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
TheportionoftherequirementconcerningcalculatingACEwasmoved
MovedtodefinitionofReportingACEand
intothedefinitionforReportingACE.Theportionoftherequirement
RequirementR3
concerninganentity’sinabilitytocalculateAceformorethan30
minuteswasmovedintoRequirementR3.
ThisrequirementshouldberetiredunderParagraph81criteria.The
firstsentencecovershavingafunctionalEMSorothersystemcapable
ofcalculatingReportingACEandcontrollingresources,though
Retire
resourcescanbedispatchedmanuallywithoutanydetrimentto
reliability.TheSDTbelievesthattheterm“operateAGC”inR7refersto
thecapabilitytocontinuouslycalculateACE,notautomaticcontrolof
resourcestotheextentBAscannottakeresourcesoff“AGC”mode.
Thebodyofthisrequirementwasmovedto
ThebodyofthisrequirementhasbeenmovedtoRequirementR2and
RequirementR2andPart8.1wasmoved
Part8.1hasbeenmovedintoRequirementR4.
intoRequirementR4
R9iscoveredinthedefinitionofReportingACE,andtheproposedR1
ensuresthattheBAdoesnotincludeanyInterchangeinitsReporting
ACEthatdoesnothaveanAdjacentBA.
RegardingR9.1,theActualNetInterchangeandScheduledNet
InterchangevaluesintheReportingACEcalculationincludeprovisions
Retire
fortheBalancingAuthoritytoincludeitshighvoltagedirect(HVDC)link
toanotherasynchronousinterconnection.Byassuringthevaluesare
handledconsistentlyintheactualandscheduledInterchangeterms
includedintherealͲtimeReportingACEbydefinition,theBalancing
Authorityisnotbeinginstructed“how”toimplementtheHVDClink,
butallowedtodecidethemethoditwilluse.
BALͲ005Ͳ0.2bR16
BALͲ005Ͳ0.2bR15
BALͲ005Ͳ0.2bR14
BALͲ005Ͳ0.2bR13
BALͲ005Ͳ0.2bR12
BALͲ005Ͳ0.2bR11
BALͲ005Ͳ0.2bR10
Requirementin
ApprovedStandard
3
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
MovedtoRequirementR1
ThisrequirementhasbeenmovedtoRequirementR1.
Theportionoftherequirementconcerningcommontime
MovedtoRequirementR1andRequirement synchronizationwasmovedintoRequirementR1.Theportionofthe
R7
requirementconcerninganequipmenterrorwasmovedinto
RequirementR7.
MovedtoRequirementR5andRequirement ThisrequirementhasbeenmovedintoRequirementR5and
R8
RequirementR8.
ThisrequirementisduplicativeoftheintentofEOPͲ008ͲLossof
Retired
ControlRoomFunctionality.
MovedtoRequirementR5
ThisrequirementhasbeenmovedintoRequirementR5.
BALͲ005Ͳ0.2bR17
Requirementin
ApprovedStandard
4
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
ThisrequirementwhichaddressaccuracyofRTUandtransducersis
meaninglessintoday’sworld.RTUsdonotquantizemeasurement
anymore,thesearedonebyrelayormeters.Transducersarenotused
anymoreandhavebeenreplacedbymetersandrelayswhichmeasure
quantities.Thisrequirementshouldberestoredsuchthatitactually
supportsanaccuratecalculationofACEandproperoperationofAGC
Partiallyretired(partiallycapturedinnew
byspecifyingaccuracyrequirementsforalltelemetryassociatedwith
RequirementR4)
ACE(Frequency,MWandtheassociatedsensingdevicesand
telemetry).Inaddition,theinterpretationeffective8/27/2008inBALͲ
005Ͳ0.2.bforR17statesthatthisrequirementisspecifictothe
equipmentusedtodeterminethefrequencycomponentrequiredfor
reportingACE.ThisisnowbeingcapturedinRequirementR4.
BALͲ006Ͳ2R4
BALͲ006Ͳ2R5
BALͲ006Ͳ2R3
Requirementin
ApprovedStandard
BALͲ006Ͳ2R1
BALͲ006Ͳ2R2
Standard:BALͲ006Ͳ3–InadvertentInterchange
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Nochange
Nochange
Nochange
Nochange
MovedtoBALͲ005Ͳ1RequirementR1and
Thisrequirementdirectlyimpactstheabilitytocalculateanaccurate
RequirementR8
ReportingACEvalue.
Nochange
Nochange
Nochange
Nochange
Transition of BAL-006-2 to BAL-006-3
Project 2010-14.2.1 Mapping Document
BALͲ005Ͳ0.2bR1
BALͲ005Ͳ0.2bR1
BALͲ005Ͳ0.2bR1
Requirementin
ApprovedStandard
FACͲ001Ͳ2R1
FACͲ001Ͳ2R2
FACͲ001Ͳ2R3
FACͲ001Ͳ2R4
Standard:FACͲ001Ͳ3–FacilityInterconnectionRequirements
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R5
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R6
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R7
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
Transition of FAC-001-2 to FAC-001-3
Project 2010-14.2.1 Mapping Document
CalculatingandUsingReportingACEinaTieLineBiasControlProgram
Introduction:
TieLineBias1(TLB)controlhasbeenusedasthepreferredcontrolmethodinNorthAmericafor75years.Inthe
early1950’sthetermAreaControlError(ACE)wasdevelopedforthespecificimplementationofcoordinatedTie
LineBiascontrolnowinusethroughouttheworld.Thisdocumentprovidesresponsibleentitiesguidelinesfor
usingbothrequiredspecificsandthebestpracticesforcalculatingandusingReportingACE2incoordinationwith
othermeasurestoprovidereliablefrequencycontrol.Whiletheincorporationofthesebestpracticesisstrictly
voluntary;reviewing,revising,ordevelopingaprocessusingthesepracticesishighlyencouragedtopromote
andachievereliabilityfortheBulkElectricSystem.
ThefollowingdefinitionsareincludedintheNERCGlossary:
Definition:
5/11/2015
ActualFrequency
FA
TheInterconnectionfrequencymeasuredinHertz(Hz).
Definition:
5/11/2015
ActualNetInterchange
NIA
ThealgebraicsumofactualmegawatttransfersacrossallTieLines,includingPseudoͲTies,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection.ActualmegawatttransfersonasynchronousDC
tielinesdirectlyconnectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
1
2
CapitalizedtermsholdthesamedefinitionasintheNERCglossarythroughoutthisdocument.
TheCPS1measurewasamongthefirstoftheresultsbasedmeasuresdevelopedbyNERC.Itdefinednothowtoperform
control,butinsteaddefinedthetargetcontrolresultsthatweretobeachieved,andamethodtomeasurewhetherornot
thatdefinedcontroltargethadbeenmet.Asaresult,whenCPS1wasimplemented,theACEEquationusedinthat
measurewasalsospecifiedwithinthatstandard.
Historically,AreaControlError(ACE)hasbeenusedtodescribemanytermsinvolvedinTLBControl.WithinaBAA’s
AutomaticGenerationControl(AGC)algorithmtheremaybemorethanoneACEvalueinuse.Insomesystems,theACE
isfilteredpriortodeterminingcontrolactionsinordertosmooththecontrolsignals;or,theremaybeadditional“feedͲ
forward”termsaddedtoACEinanticipationoffuturechanges(e.g.anticipatedramps,changesinambientlightat
sunriseorsunset).TheremaybegaintermsthatmodifycertainvariablessuchastheFrequencyBiasSettingtoimprove
thequalityofcontrolforthespecificcharacteristicsofthatparticularBAA.
SomeauditorshaveraisedcomplianceissuerelatedtotheuseofsuchmodificationstotheACEusedwithintheLoadͲ
FrequencyControl(LFC)system(alsoreferredtoasAGC)andrequiredchangesintheAGCsystemtoconformtothe
definitionofACEinBALͲ001.Theterm“ReportingACE”wasdevelopedandisusedinplaceofthetermACEtoprovidea
consistentperformancemeasurementusingReportingACEandtoremoveanyunnecessaryrestrictionsonthe
specificationofACEwithintheLFCsystem.
1
2
Definition:
AutomaticTimeErrorCorrection
IATEC 5/11/2015
TheadditionofacomponenttotheACEequationfortheWesternInterconnectionthatmodifiesthecontrol
pointforthepurposeofcontinuouslypayingbackprimaryInadvertentInterchange(PII)tocorrect
accumulatedtimeerror.AutomaticTimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Τࢌࢌࢋࢇ
܂ۯ۳۱
ࢇࢉࢉ࢛
ൌ
ሺି܇ሻכ۶
whenoperatinginAutomaticTimeErrorCorrectionmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
x
x
x
x
x
x
x
x
x
x
x
x
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAAbetween0.2*|Bi|andL10,0.2*|Bi|LmaxL10.
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare(RMS)
valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragivenyear.The
bound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
Y=Bi/BS.
H=NumberofhoursusedtopaybackprimaryInadvertentInterchangeenergy.ThevalueofHissetto3.
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactual–Bi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor,
where:
ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontimemonitorcontrol
centerclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲPeak
accumulationaccountingisrequired,
where:
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࢎ࢛࢘࢟
Definition:
FrequencyBiasSetting
B
4/1/2015
Anumber,eitherfixedorvariable,usuallyexpressedinMW/0.1Hz,includedinaBalancingAuthority’sArea
ControlErrorequationtoaccountfortheBalancingAuthorityArea’sinverseFrequencyResponsecontribution
totheInterconnection,anddiscourageresponsewithdrawalthroughsecondarycontrolsystems.
3
Definition:
5/11/2015
InterchangeMeterError
IME
Aterm,normallyzero,usedintheReportingACEcalculationtocompensatefordataorequipmenterrors
affectinganyothercomponentsoftheReportingACEcalculation.
Definition:
ReportingACE
RACE 5/11/2015
ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError(ACE)measuredinMWincludes
thedifferencebetweentheBalancingAuthorityArea’sActualNetInterchangeanditsScheduledNet
Interchange,plusitsFrequencyBiasSettingobligation,pluscorrectionforanyknownmetererror.Inthe
WesternInterconnection,ReportingACEincludesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
=
ActualNetInterchange.
x NIA
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
=
AutomaticTimeErrorCorrection.
x IATEC
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciplesofTieͲlineBias
(TLB)ControlandrequiretheuseofanACEequationsimilartotheReportingACEdefinedabove.Any
modification(s)tothisspecifiedReportingACEequationthatis(are)implementedforallBAAsonan
Interconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBiascontrolwillprovidea
validalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’
generation,load,andlossisthesameastotalInterconnectiongeneration,load,andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimesandthesumof
allBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEtermcorrectsforknown
meteringorcomputationalerrors.)
4
Definition:
3/16/2007
ScheduledFrequency
FS
60.0Hz,exceptduringamanualTimeErrorCorrection.
Definition:
5/11/2015
ScheduledNetInterchange
NIS
Thealgebraicsumofallscheduledmegawatttransfers,includingDynamicSchedules,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection,includingtheeffectofscheduledramps.
ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromScheduledNetInterchange.
Structure:
TheeffectiveuseofReportingACEwithinaTLBcontrolprogramshouldaddressthefollowingcomponents:
(I)
(II)
(III)
(IV)
(V)
(VI)
(VII)
(VIII)
ManagementRolesandExpectations
InformationTechnologyRoles
SystemOperatorRoles
ManualSourceDataEntry
AutomaticallyCollectedSourceData
UsesofReportingACE
HistoricDataManagement
SpecialConditionsandCalculations
Eachindividualcomponentshouldaddressprocessesandprocedures,evaluationofanyissuesorproblems
alongwithsolutions,testing,training,andcommunications.Theseprovisionsandactivitiestogetherwillbe
referredtoastheTieLineBiascontrolprogram.
EachresponsibleentityshouldevaluateallofitsusesforReportingACEinitsoperationsanditsreliability
measurement.ReportingACEisoneofthemostimportantsinglemeasurementsavailabletoindicatethe
currentstateoftheResponsibleEntity’scontributiontointerconnectionreliability.3ReportingACEisalsoused
asanintegralpartofthemeasurementsusedinBALͲ001andBALͲ002.Technicalrequirementsassociatedwith
theparametersusedinthecalculationofReportingACEarespecifiedinBALͲ003andBALͲ005.
I.
ManagementRolesandExpectations
ManagementplaysanimportantroleinmaintaininganeffectiveTLBcontrolprogram.The
managementroleandexpectationsbelowprovideahighͲleveloverviewofthecoremanagement
responsibilitiesrelatedtoeachTieLineBiascontrolprogram.Themanagementofeachresponsible
entityshouldtailortheserolesandexpectationstofitwithinitsownstructure.
a. Setexpectationsforsafety,reliability,andoperationalperformance.
3
WhenconfiguredwithaFrequencyBiasSettingequaltotheactualFrequencyResponseoftheBAA,ReportingACEwill
reflecttheBAA’sobligationtomatchitsactualinterchange,lesstheimpactfromitscurrentFrequencyResponseoffset,
toitsscheduledinterchange.
5
b.
c.
d.
e.
II.
AssurethataTLBcontrolprogramexistsforeachresponsibleentityandiscurrent.
ProvideannualtrainingontheTLBcontrolprogramanditspurposeandrequirements.
EnsuretheproperexpectationofTLBcontrolprogramperformance.
Shareinsightsacrossindustryassociations.
InformationTechnology(IT)Roles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEandsourceinformationarealwayscurrentandcorrect.
c. ImplementtheTLBcontrolprograminRealͲtime.
d. EnsurethattheEMSsupportsthemanualdataentryofallsourcedatarequiredtobeenteredbyIT
staff,systemoperationsstaff,andSystemOperatorsandproperlymanagesthatdataonceentered.
e. EnsurethattheEMSsupportsandmanagestheautomaticcollectionofallsourcedatathatis
requiredtobemeasuredinrealͲtimethroughtelemetryanddataexchangeincludingdataquality
informationtoindicatedatavalidity.
f. EnsurethattheprogramsthatmanagedatausedtocalculatecomponentsofReportingACE,
ReportingACEitself,andsubsequentmeasuresbasedonReportingACEareuptodateandcorrect
asidentifiedby,butnotlimitedtothefollowingcalculationsandequations:
1) ActualNetInterchange4(NIA):
AllBAAsinvolvedaccountforthepowerexchangeandassociatedtransmissionlossesasactual
interchangebetweentheBAAs,bothintheirACEandReportingACEequationsandthroughout
alloftheirenergyaccountingprocesses.
i. Calculateforeachscan.5
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
4
Bydefinition“ActualmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromActualNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielinesconnectedto
anotherinterconnectionisprovidedin“SpecialConditionsandCalculations”sectionofthisdocument.
5
ActualNetInterchangescanͲratevaluesarealsousedasoneoftheprimaryinputstothecalculationofFrequency
ResponseMeasure(FRM)onFRSForm1andFRSForm2.
6
2) ScheduledNetInterchange6(NIS):
i. Calculateforeachscan.
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
(Thisvaluediffersfromtheblockaccountingvalue.)
Note: DynamicSchedulesaretobeaccountedforasInterchangeSchedulesbythesource,
sink,andcontractintermediaryBAA(s),bothintheirrespectiveACEandReportingACE
equations,andthroughoutalloftheirenergyaccountingprocesses.
3) FrequencyError('F=(FA–FS)):
i. Calculateforeachscan.
ii. CalculateclockͲminuteaveragefromvalidsamplesavailablewithineachclockͲminute7
whereatleasthalfofthescanͲratesamplesarevalid.
4) FrequencyTriggerLimit–Low(FTLLow)8:
CalculatetheFrequencyTriggerLimit–LowforeachclockͲminutewhereatleasthalfofthescan
ratesamplesarevalidbysubtractingthreetimesEpsilon1fromtheScheduledFrequency(FS).
5) FrequencyTriggerLimit–High(FTLHigh)9:
CalculatetheFrequencyTriggerLimit–HighforeachclockͲminutewhereatleasthalfofthe
scanratesamplesarevalidbyaddingthreetimesEpsilon1totheScheduledFrequency(FS).
6) AccumulatedprimaryInadvertentInterchange(PII):CalculatedeachhourforWECCBAAsonly.
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࢎ࢛࢘࢟
7) AutomaticTimeErrorCorrection(IATEC):CalculateforeachhourforWECCBAAsonlyfor
inclusionintheACEandReportingACEEquationforthenexthour.
Τࢌࢌࢋࢇ
܂ۯ۳۱
ࢇࢉࢉ࢛
ൌ
ሺିࢅሻࡴכ
whenoperatinginATECmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
6
Bydefinition“ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherinterconnection
areexcludedfromScheduledNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielines
connectedtoanotherinterconnectionisprovidedinthe“SpecialConditionsandCalculations”sectionofthisdocument.
7
ClockͲminuteaveragesareusedforthecalculationofACEandFrequencyErrorinCPS1andBAALtoeliminatethe
transientvariationsoftieͲlineflowsandfrequencyerrorusedinthecalculationofperformancemeasures.TheoneͲ
minuteperiodwaschosenbecauseitisevenlydivisiblebyallwholeͲsecondscanrateslessthanthemaximumspecified
scanrateofsixseconds.ThisassuresgreatercomparabilityofperformancedataamongBAswithdifferentscanrates.
8
Thisvariablecouldbeenteredmanuallyaslongasitischangedeverytimeamanualtimeerrorcorrectionisstartedor
stopped.Ifmanualtimeerrorcorrectioniseliminated,itcouldbecomeaconstantandenteredmanually.
7
8) ReportingACE:
i. Calculateforeachscan.
ii. CalculatedaverageforeachclockͲminuteforBAAsusingafixedFrequencyBiasSetting
whenatleasthalfofthevaluesarevalid.9
9) ComplianceFactor10:
i. CalculateforeachscanwherebothReportingACEandFrequencyErrorarevalid.
ii. CalculateforeachclockͲminutewhereboththeaverageclockͲminuteFrequencyErrorand
theaverageclockͲminuteReportingACEarevalid.11
10) ClockͲhourcompliancefactor8:
CalculateforeachhourbysummingthevalidclockͲminutecompliancefactorsforthehourand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthehour.
11) Monthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthemonthanddividingby
thenumberofvalidclockͲminutecompliancefactorsinthemonth.
12) 12Ͳmonthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthe12Ͳmonthperiodand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthe12Ͳmonthperiod.
13) CPS1compliancefactor:
CalculatetheCPS1compliancefactorbydividingthe12Ͳmonthcompliancefactorbythesquare
oftheEpsilon1valuefortheInterconnection.
14) CPS1:
i. CalculatetheCPS1scanrateperformancebydividingthescanratecompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachscanwitha
validcompliancefactor.
ii. CalculatetheCPS1clockͲminuteperformancebydividingtheclockͲminutecompliance
factorbythesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthat
valuefrom2andmultiplyingtheresultby100toconverttoapercentageperformancefor
eachclockͲminutewithavalidcompliancefactor.
iii. CalculatetheCPS1clockͲhourperformancebydividingtheclockͲhourcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
9
TheaverageofthevalueoftheratioofthescanratevalueofReportingACEdividedbythescanratevalueofͲ10times
theFrequencyBiasSettingforthoseBAsusingavariableFrequencyBiasSetting,whereatleasthalfoftheratiovalues
arevalid.
10
UsedforCPS1.
11
ThecompliancefactoriscalculatedwhentheaverageofthevalueoftheratioofthescanratevalueofReportingACE
dividedbythescanratevalueofͲ10timestheFrequencyBiasSettingforthoseBAsusingavariableFrequencyBias
Setting,whereatleasthalfoftheratiovaluesarevalidandtheaverageclockͲminuteFrequencyErrorisvalid.
8
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
iv. CalculatetheCPS1monthlyperformancebydividingthemonthcompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲminute
withavalidcompliancefactor.
v. CalculatetheCPS112Ͳmonthperformancebydividingthe12Ͳmonthcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
15) BalancingAuthorityACELimitͲLow(BAALLow):
i. CalculatethescanrateBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
16) BalancingAuthorityACELimitͲHigh(BAALHigh):
i. CalculatethescanrateBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
17) BalancingAuthorityACELimitͲLowCompliance:
i. AlarmBAALLowpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisbelowtheclockͲminuteBAALLow.
ii. IndicateBAALLownonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
belowtheclockͲminuteBAALLowformorethan30ͲconsecutiveclockͲminutes.
18) BalancingAuthorityACELimitͲHighCompliance:
i. AlarmBAALHighpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisabovetheclockͲminuteBAALHigh.
ii. IndicateBAALHighnonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
abovetheclockͲminuteBAALHighformorethan30consecutiveclockminutes.
g. EnsurethattheEMSsupportstheretentionofallhistoricdataincludingdataqualityinformation
requiredtoberetainedtosupportcontinuingoperationsandauditrequirements.
9
h. EnsurethattheEMSsupportsandmanagesthepresentationofallinformationrequiredtobe
availabletotheSystemOperatorforrealͲtimeoperations,operationsstaffforevaluationof
operations,andauditorsforcomplianceconfirmation.
i.
ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
III.
SystemOperatorandOperationsStaffRoles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEinformationisalwayscurrentandcorrect.
c. ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
d. ImplementtheTLBcontrolprograminRealͲtime.
IV.
ManualSourceDataEntry
ReportingACEiscalculatedinRealͲtime,atleasteverysixseconds12,bytheResponsibleEntity’sEnergy
ManagementSystem(EMS),andmaybepartiallybasedonsourcedatamanuallyenteredintothat
system.Thefollowingsourcedatamaybeentered:
NIA(ActualNetInterchange):Thetelemetryvaluesofactualtieflows,includingpseudoͲties,between
AdjacentBalancingAuthorityAreasmaynotbeavailablefromanautomaticcollectionsource,
requiringmanualentryofestimatedflows.Thesemanualentriesshouldbeperformedina
mannerthatreasonablyassuresequalmagnitudeandoppositesignvaluesareusedbythe
AdjacentBalancingAuthorityAreasenteringthemanualdata.Iftheactualflowestimatesare
thesamefortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedto
thetwoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failureto
matchactualflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
NIS(ScheduledNetInterchange):Thepowertransferschedules,includingtheschedulerampswhere
applicable,areprocessedbytheEMS.Ifscheduledflowestimatesareequalandhaveopposite
signsfortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedtothe
twoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failuretomatch
scheduledflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
B(FrequencyBiasSetting):TheFrequencyBiasSetting,orminimumrequiredvalue,fortheBalancing
AuthorityAreaisspecifiedbycalculationsperformedaspartofcompliancewithBALͲ003Ͳ1Ͳ
FrequencyResponseandFrequencyBiasSetting;
R2.
EachBalancingAuthorityAreathatisamemberofamultipleBalancingAuthority
AreaInterconnectionandisnotreceivingOverlapRegulationServiceandusesafixed
FrequencyBiasSettingshallimplementtheFrequencyBiasSettingdeterminedin
accordancewithAttachmentA,asvalidatedbytheERO,intoitsAreaControlError
12
BALͲ005Ͳ1BalancingAuthorityControlͲR2.TheBalancingAuthorityshallusenogreaterthanasixͲsecondscanratein
acquiringdatanecessarytocalculateReportingACE.
10
(ACE)calculationduringtheimplementationperiodspecifiedbytheEROandshall
usethisFrequencyBiasSettinguntildirectedtochangebytheERO.13
10isthefactor(100.1Hz/Hz)thatconvertstheFrequencyBiasSettingunitstoMW/Hz.
FS(ScheduledFrequency):ScheduledFrequency,normally60Hz,ismanuallyadjustedonacoordinated
basiswhendirectedtodosobytheInterconnectionTimeMonitorasspecifiedinBALͲ004Ͳ0.14It
isimportantforallBAAsonaninterconnectiontomaketheseadjustmentsonacoordinated
basissothatallBAAsarecontrollingtothesameScheduledFrequencyatalltimes.
IME(InterchangeMeterError):Thisterm,normallyzero,isavailableforusebytheSystemOperatoror
operationsstafftoaddacorrectiontermintheReportingACEcalculationtocompensatefor
dataorequipmenterrorsaffectinganyothercomponentsidentifiedbyanalysisofhistoricdata
demonstratingtheexistenceoferrors,usuallyerrorsbetweenintegratedhourlyscanͲratedata
andhourlyagreedtoaccumulatedmeterdata.(SeetheSpecialConditionsandCalculations
sectionofthisdocumentforadditionalinformation)
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|B|andL10,0.2*|B|чLmaxчL10.
YisnormallycalculatedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.
Hisnormallysetto3andusedbytheATECprogramintheEMSforBAsontheWestern
Interconnection.Itrepresentsthenumberofhoursoverwhichtheprimaryinadvertent
interchangeispaidback.
BSisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Itrepresentsthe
sumoftheminimumFrequencyBiasSettingsforallBAAsontheInterconnection.
ȴTEisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Insomecases,it
maybecalculatedbytheEMSbasedonthefactorsintheȴTEequation.ȴTEisthehourly
changeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor.
TDadjisanadjustmentforthedifferencesbetweenthelocalclockinthelocaltimestandardandthe
InterconnectiontimemonitorcontrolcenterclockssothatthelocalEMScancalculatethe
correctȴTEfortheBAAsandusedbytheATECprogramintheEMSforBAAsontheWestern
Interconnection.
TEoffsetisenteredasinstructedbytheInterconnectiontimemonitor.
H1istheRMSLimitforthe1Ͳminuteaveragefrequencyerrorfortheinterconnection.
13
Asanoteofinterest,thenewproceduresputforthwithBALͲ003Ͳ1willresultinthereductionofminimumFrequency
BiasSettingvaluesonthemultipleBAinterconnectionstobringthemclosertothenaturalmeasuredFrequency
Responseoftheinterconnection.TherulerequiringaminimumFrequencyBiasSettingof1%ofpeakloadintheNERC
Standardsdatesbackto1962whenNAPSIC,theprecursortotheNERCOperatingCommittee,codifiedthe
recommendationsoftheInterconnectedSystemsGroupmadein1956tosetaminimumof50%ofthenaturalmeasured
responsewhichwas2%ofpeakloadatthattime.The1%figureisnowmorethan200%ofthenaturalmeasured
responsefortheEasternInterconnectionandinsomecasesisapproachingavaluethatcouldresultininstabilitybybeing
toohigh.Thelogicjustifyingaminimumofthenaturalresponseisstillvalid.
14
Thisisconsistentwithcondition3intheReportingACEDefinition:“TheuseofacommonScheduledFrequencyFSforall
areasatalltimes.”
11
V.
AutomaticallyCollectedSourceData
ReportingACEiscalculatedinRealͲtime,atleastasfrequentlyaseverysixseconds15,bytheresponsible
entity’sEnergyManagementSystem(EMS)predominantlybasedonsourcedataautomaticallycollected
bythatsystem.Also,thedatamustbeupdatedatleasteverysixsecondsforcontinuousscantelemetry
andupdatedasneededforreportͲbyͲexceptiontelemetry.
Inaddition,dataqualityinformation(usuallyintheformofdataqualityflagsassociatedwitheachdata
value)mustberetainedandpresentedinrealͲtimetotheSystemOperators.Thisdataquality
informationispresentedtotheSystemOperatortohavesituationalawarenesswithrespecttothe
qualityofthedatainputsandfinalcalculatedresult.Itislaterusedtodeterminewhichdataisvalidfor
useinperformancecalculationssuchasCPS1,BAAL,DCS,andfrequencyresponseobligation(FRM).
NIA(ActualNetInterchange):ThetieͲlinevaluerepresentingeachtieͲlineflowandpseudoͲtiequantity
iscollectedattherequiredscanrateofsixsecondsorless.16,17,18,19Datathatisofquestionableaccuracy
ortimelinessisflaggedwithanappropriatedataqualityflag.Thisinformationispresentedtothe
SystemOperatortosupportsituationalawareness.20TheEMSsumstheindividualflowvaluesonalltie
linesandpseudotieswithalladjacentBAAsatthescanrateandincludesthisvalueasNIAinthe
ReportingACEequationcalculation.TheresultisaseriesofNIAvaluesattheEMSscanrateand
associateddataqualityflags.Theassociateddataqualityofthetelemetryelementispassedtothe
resultofallcalculationsusingthatelement.
NIS(ScheduledNetInterchange):MostinterchangeschedulesandsomeDynamicSchedulesare
enteredintotheEMSinasummaryformateitherasindividualschedules,schedulenetswitheach
AdjacentBalancingAuthorityArea,orafinalScheduledNetInterchange.Theseschedulesareconverted
intoscanͲrateschedulesbytheEMS.TheEMScalculatestheScheduledNetInterchange,where
applicable,bysummingallindividualschedulevaluesornetswitheachAdjacentBalancingAuthority
AreaforallregularandDynamicSchedulesandincludestheresultasNISintheACEequation.
FA(ActualFrequency):Actualfrequencyisprovidedbyafrequencymeasuringdeviceattheaccuracy
specifiedinBALͲ00521attheEMSscanrate.Ifafrequencyvalueisnotavailable,thevalueforthatscan
ismarkedinvalid.
15
BALͲ005Ͳ1BalancingAuthorityControl–“R2.TheBalancingAuthorityAreashallusenogreaterthanasixͲsecondscan
rateinacquiringdatanecessarytocalculateReportingACE.”
16
DatatransmittedatarateslowerthanthescanrateoftheremotesensingequipmentmayrequiretheinclusionofantiͲ
aliasingfilteringatthesourceofthemeasurementtoeliminatetheriskofaliasinginthedatatransmittedtotheEMS.
Seetheattacheddocumenttitled“AntiͲaliasingFiltering.”
17
ItisacceptabletocollecttieͲlineflowdatafromRTUsthatusereportbyexceptionaslongasthoseRTUscansupportthe
scanrateofsixsecondsorlesswhendataischangingrapidlyandbothadjacentBAAsarereceivingcomparabledatato
keepthemeasuredflowsequivalent.
18
ThesixͲsecondscanratenotonlyassuresthatdatacollectedisclosetoRealͲtime,italsolimitsthelatency(timeskew)
associatedwiththedatacollection.
19
Theaccuracyoftheflowdataissetbythoseusingtheflowdatafortransmissionflowmanagement.AswithallACEdata,
aslongasbothadjoiningBAAsareusingthesamevaluesfortieͲlineflow,theeffectsofanyerrorinflowmeasurement
willbeconfinedtothetwoadjacentBAAs.
20
Indicationsofsuspectdataareusuallyindicatedwithcolorchangesand/oralarms.
21
BALͲ005–AutomaticGenerationControlspecifiesanaccuracyofч0.001Hz(equivalenttoч+/Ͳ0.0005Hz)fortheDigital
FrequencyTransducer.
12
IIactual(InadvertentInterchange):ThistermisonlyusedintheWesternInterconnectionACEcalculation.
InadvertentInterchange“Actual”fortheprevioushouriscalculatedbytheEMSfromtheprevious
hour’sdataasthedifferencebetweentheintegratedhourlyaverageScheduledNetInterchangeandthe
integratedhourlyaverageActualNetInterchange.(Blockschedulesarenotusedforthiscalculation.)
t(ManualTimeErrorcorrectionminutesinthehour):ThenumberofminutesofmanualTimeError
correctioninthehour.
VI.
UsesofReportingACE
a. ReportingACEiscurrentlyusedtomeasuresecondaryfrequencycontrolwithinTLBcontrolonallof
theInterconnections.22Consequently,ReportingACEisoneoftheprimarymeasurement
parametersinmanyoftheNERCBalancingStandards.Thefollowingstandardsrequiretheuseof
ReportingACEaspartoftheperformancemetricsorsetrequirementsassociatedwiththe
calculationofReportingACE.
i. BALͲ001Ͳ1–RealPowerBalancingControlPerformanceandBALͲ001Ͳ2–RealPowerBalancing
ControlPerformance.
ii. BALͲ002Ͳ1–DisturbanceControlPerformanceandBALͲ002Ͳ2–DisturbanceControlStandard–
ContingencyReservefromaBalancingContingencyEvent(whenapproved).
iii. BALͲ005Ͳ0.2b–AutomaticGenerationControlandBALͲ005Ͳ1–BalancingAuthorityControl
(whenapproved).
iv. BALͲ006Ͳ2InadvertentInterchange.
b. TheindustrymayalsoconsidertheuseofReportingACEinthefuturetoevaluatetherules
associatedwithtransmissionloading.
VII.
VIII.
HistoricDataManagement
TheindustrycurrentlyrequirestheretentionofdatasupportingthecalculationofReportingACEand
compliancemeasurementsbasedinpartonReportingACEtosupporttheNERCcomplianceaudit
process.ThisdataretentionmustbeconsideredasanintegralpartoftheReportingACEand“TLB
controlprogram”.
SpecialConditionsandCalculations
a. IME(InterchangeMeterError)Thisterm,normallyzero,isavailableforusebytheSystemOperator
oroperationsstafftoaddacorrectiontermintheReportingACEcalculation.Itcompensatesfor
dataorequipmenterrorsaffectinganyothercomponentsofReportingACEidentifiedbyanalysisof
historicdata.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourlyagreed
toaccumulatedmeterdata.TheprocessusedforincludingadjustmentsintheIMEtermshouldbe
basedongoodqualitycontrolmethods.23
22
OnsingleBAAInterconnections,theACEEquationreducestoasingleterm,Ͳ10B(FA–FS),becausetherearenotielines
orschedulestoincludeinthefirstterm,(NIA–NIS),andthereisnoIMEtermtocorrectfortielineordynamicschedule
measurementerrorsinthefirstterm.
23
AdjustmentstotheIMEtermshouldfollowgoodqualitycontrolmethodsandexcludetamperingasdemonstratedbythe
Deming’sFunnelExperiment,http://blog.newsystemsthinking.com/wͲedwardsͲdemingͲandͲtheͲfunnelͲexperiment/.
13
ThegoalassociatedwiththeuseoftheIMEistoencouragethescanͲratevaluesofactualand
scheduledinterchangebetweenAdjacentBalancingAuthorityAreastobeequalinmagnitudeand
haveoppositesigns.24Wheninitiallyconfigured,allBAAsused“AnalogtoDigital”convertersand
“DigitaltoAnalog”converterstotransmittieͲlineflowsfromthecommonmeteringpointrequired
inthestandardstotheBAA’sEMS.These“AtoD”and“DtoA”convertersaresubjecttoerrorand
requirefrequentcalibration,andalthough,manyhavebeenreplacedbydigitaltelemetry,theystill
existandrequireoversight.
ManagementoftheaccuracyofthescanratevaluesusedintheReportingACEequationcanbe
accomplishedbycreatingaprocessthatcomparesthescanratevaluestoothervaluesthathavea
greaterlikelihoodofagreeingwiththesamevaluesfortheAdjacentBAA.Thosevaluesareadjusted
asnecessaryusingtheIMEterm.EnergyManagementSystemsarecapableofintegratingthescan
ratevaluesusedforthecalculationofReportingACEandprovidingthoseintegratedvaluesfor
comparisontotheaccumulatedmegawattͲhourvaluesforthesamemeters.Iftheintegratedscan
ratevaluesareclosetotheaccumulatedmegawattͲhourvalues,thenonecanconcludethatthe
scanratevaluesaccuratelyrepresenttheaccumulatedvalues.Thefinalstepinthisprocessincludes
acomparisonandagreementontheaccumulatedmegawattͲhourvaluesbetweentheAdjacent
BAAssharingthemeasurement.Thisinformationusedinconjunctionwithasimilaranalysisofthe
scanratevaluesforthesamemeasurementbytheAdjacentBalancingAuthorityAreaincluding
analysisofanydifferencesbetweentheaccumulatedvaluesandtheagreedtovalues.Thistotal
processprovidesreasonableassurancethatthetielineflowsorthedynamicschedulesusedby
AdjacentBAAsareconsistentwithoneanotherconfiningcontrolproblemswithintheboundariesof
theAdjacentBAAs.
TheseerrorcorrectionadjustmentscanbeusedtocorrecterrorsintheNIAorNIS25termsfor
ReportingACEandothermeasurementsthatdependuponanaccurateActualNetInterchange
and/oranaccurateScheduledNetInterchange.Thesamelogicandevaluationprocessesthatare
validforinclusionintheIMEtermoftheReportingACEequationshouldalsobevalidasadjustments
tothescanratetieͲlineflowsusedforthemeasurementofFrequencyResponseaspartoftheBALͲ
003Ͳ1.
b. UseofSourceͲSinkPairsforAsynchronousDCTieLinestoAnotherInterconnection:Oneofthe
primaryrulesforinsuringthevalidityoftheReportingACEequationis,“Allportionsofthe
InterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’generation,load,and
lossisthesameastotalInterconnectiongeneration,load,andloss.”Thisisaccomplishedby
requiringtheinclusioninReportingACEofalltielines,pseudoties,interchangeschedulesand
DynamicSchedulestoAdjacentBalancingAuthorityAreasandonlyAdjacentBalancingAuthority
AreasonthesameInterconnection,andrequiringtheexclusionofallasynchronousDCtielinesand
associatedscheduledinterchangewithBalancingAuthorityAreasonadifferentInterconnection
24
AslongasthetielineflowsandscheduledflowsmatchforAdjacentBalancingAuthorityAreas,anyproblemswiththe
measurementofbalancingontheinterconnectionwillbeconfinedtowithintheboundariesofthoseAdjacentBalancing
AuthorityAreas.
25
ErrorsintheNISwouldonlyoccurandonlysupportcorrectionincaseswherethereisameasurementerrorassociated
withaDynamicSchedule.
14
fromReportingACE.Followingthissimpleruleinsuresthatallloads,lossesandgenerationare
properlyincludedwitheachInterconnection.
InsteadofincludingthepowertransfersfromanasynchronousDCtielinebetweentwo
InterconnectionsasanormalinterchangetransferbetweentwoBAAs,thisformofpowertransfer
shouldbeincludedasthoughitisalinkedsourceͲsinkpairforthepurposesofmanagingfrequency
controlwithinatielinebiascontrolprogram.OneterminalofanasynchronousDCtielinewill
appeartothereceivingInterconnectionandreceivingBAAasanenergyresourcesimilartoa
generator.ThisisthesourceendofthesourceͲsinkpair.Theotherterminalofthesame
asynchronousDCtielinewillappeartothesupplyingInterconnectionandsupplyingBAAasan
energysinksimilartoaload.ThisisthesinkendofthesourceͲsinkpair.
InterchangetransactionslinkedtoeitherthesourceorsinkfromotherBAAsonthesame
Interconnectionasthesourceorsinkwillschedulethosetransactions,includethosetransactionsin
ReportingACE,andmanagethosetransactionsinasimilarmannertoanyotherenergytransaction.
OnlytheBAAactingasthesourceorthesinkfortheDCtielinewillexcludetheasynchronoustie
linefromitsReportingACEwhileincludingalltransactionswithAdjacentBAAsonthesame
InterconnectionassociatedwiththatsourceorsinkpowertransferintheirReportingACE.
Standards Announcement Reminder
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-3, and FAC-001-3
Initial Ballot and Non-binding Poll Open through September 14, 2015
Now Available
An initial ballot for draft one of BAL-005-1 –Balancing Authority Control, BAL-006-3 – Inadvertent
Interchange, and FAC-001-3 – Facility Interconnection Requirements and a non-binding poll of the
associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) are open through 8 p.m.
Eastern, Monday, September 14, 2015.
Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the standards
and associated VRFs and VSLs by clicking here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at [email protected] (Monday – Friday,
8 a.m. - 8 p.m. Eastern).
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 standards and
post them for an additional ballot. If the comments do not show the need for significant revisions, the
standards will proceed to a final ballot.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-3, and FAC-001-3
Formal Comment Period Open through September 14, 2015
Ballot Pools Forming through August 28, 2015
Now Available
A 45-day formal comment period for draft one of BAL-005-1 –Balancing Authority Control, BAL-006-3 –
Inadvertent Interchange, and FAC-001-3 – Facility Interconnection Requirements is open through 8
p.m. Eastern, Monday, September 14, 2015.
Commenting
Use the electronic form to submit comments on the standards. If you experience any difficulties in
using the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, August 28, 2015. Registered Ballot
Body members may join the ballot pools here.
Next Steps
An initial ballot for the standards and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 4-14, 2015.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-3, and FAC-001-3
Formal Comment Period Open through September 14, 2015
Ballot Pools Forming through August 28, 2015
Now Available
A 45-day formal comment period for draft one of BAL-005-1 –Balancing Authority Control, BAL-006-3 –
Inadvertent Interchange, and FAC-001-3 – Facility Interconnection Requirements is open through 8
p.m. Eastern, Monday, September 14, 2015.
Commenting
Use the electronic form to submit comments on the standards. If you experience any difficulties in
using the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
Join the Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, August 28, 2015. Registered Ballot
Body members may join the ballot pools here.
Next Steps
An initial ballot for the standards and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 4-14, 2015.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1 and FAC-001-3
RSAWs Posted for Industry Comment through September 14, 2015
Now Available
The draft RSAWs for BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility Interconnection
Requirements are posted on the project page for industry comment through 8 p.m. Eastern, Monday,
September 14, 2015. Submit feedback regarding the draft RSAWs to [email protected].
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-3, and FAC-001-3
Initial Ballot and Non-binding Poll Results
Now Available
A formal comment period and initial ballot for draft one of BAL-005-1 –Balancing Authority Control, BAL006-3 – Inadvertent Interchange, and FAC-001-3 – Facility Interconnection Requirements as well as a
non-binding poll of the associated Violation Risk Factors and Violation Severity Levels concluded 8 p.m.
Eastern, Monday, September 14, 2015.
The initial ballot did not receive sufficient affirmative votes for approval. Voting statistics are listed below,
and the Ballot Results page provides detailed results for the ballot and non-binding poll.
Ballot
Non-binding Poll
Quorum /Approval
Quorum/Supportive Opinions
83.81% / 55.97%
83.64% / 56.90%
Next Steps
The drafting team will consider all comments received during the formal comment period, make
revisions to the standards, and post them for an additional ballot.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Surveys
Legacy SBS (https://standards.nerc.net/)
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/27)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3
IN 1 ST
Voting Start Date: 9/4/2015 12:01:00 AM
Voting End Date: 9/14/2015 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 264
Total Ballot Pool: 315
Quorum: 83.81
Weighted Segment Value: 55.97
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
78
1
37
0.627
22
0.373
0
7
12
Segment:
2
10
0.9
2
0.2
7
0.7
0
0
1
Segment:
3
72
1
33
0.611
21
0.389
0
3
15
Segment:
4
25
1
12
0.6
8
0.4
0
2
3
Segment:
5
72
1
31
0.585
22
0.415
0
6
13
Segment:
6
44
1
23
0.639
13
0.361
0
1
7
Segment:
7
2
0.1
1
0.1
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment: 2
0.2
1
0.1
© 2016
NERC
Ver
3.0.0.0
Machine
Name:
ERODVSBSWB01
8
Segment:
9
2
0.1
0
0
1
0.1
0
1
0
Segment:
10
8
0.6
4
0.4
2
0.2
0
2
0
Totals:
315
6.9
144
3.862
97
3.038
0
23
51
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Negative
Comments
Submitted
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Negative
Third-Party
Comments
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Third-Party
Comments
1
Black Hills
Corporation
Wes Wingen
Abstain
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
None
N/A
1
Cleco Corporation
John Lindsey
None
N/A
1
Colorado Springs
Utilities
Shawna Speer
Negative
Comments
Submitted
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Affirmative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Negative
Third-Party
Comments
1
Dominion - Dominion
Virginia Power
Larry Nash
Negative
Comments
Submitted
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
None
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Negative
Comments
Submitted
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
Negative
Third-Party
Louis Guidry
Douglas Webb
Comments
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
Abstain
N/A
1
Hydro-Qu?bec
TransEnergie
Martin Boisvert
Negative
Comments
Submitted
1
IDACORP - Idaho
Power Company
Molly Devine
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
Affirmative
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
None
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Third-Party
Comments
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power
Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public
Power District
Jamison Cawley
Negative
Third-Party
Comments
1
New York Power
Authority
Salvatore Spagnolo
Affirmative
N/A
Scott Miller
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Negative
Comments
Submitted
1
NiSource - Northern
Indiana Public
Service Co.
Julaine Dyke
Negative
Third-Party
Comments
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Abstain
N/A
1
Oncor Electric
Delivery
Rod Kinard
Affirmative
N/A
1
OTP - Otter Tail
Power Company
Charles Wicklund
Negative
Third-Party
Comments
1
Peak Reliability
Jared Shakespeare
Affirmative
N/A
1
PHI - Potomac
Electric Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
Abstain
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Theresa Rakowsky
Negative
Comments
Tammy Porter
Inc.
Submitted
1
Sacramento
Municipal Utility
District
Tim Kelley
1
Salt River Project
1
Joe Tarantino
Affirmative
N/A
Steven Cobb
None
N/A
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
None
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Negative
Comments
Submitted
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
Third-Party
Comments
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
Affirmative
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Negative
Comments
Submitted
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
Bret Galbraith
1
Xcel Energy, Inc.
Dean Schiro
Negative
Comments
Submitted
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Negative
Comments
Submitted
2
Electric Reliability
Council of Texas, Inc.
christina bigelow
Negative
Third-Party
Comments
2
Herb Schrayshuen
Herb Schrayshuen
Negative
Third-Party
Comments
2
Independent
Electricity System
Operator
Leonard Kula
Negative
Comments
Submitted
2
ISO New England,
Inc.
Michael Puscas
Negative
Third-Party
Comments
2
Midcontinent ISO,
Inc.
Terry BIlke
Negative
Comments
Submitted
2
New York
Independent System
Operator
Gregory Campoli
Negative
Third-Party
Comments
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power
Pool, Inc. (RTO)
Charles Yeung
None
N/A
3
Ameren - Ameren
Services
David Jendras
Negative
Comments
Submitted
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
Abstain
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lisa Martin
Affirmative
N/A
3
Avista - Avista
Corporation
Scott Kinney
None
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Negative
Comments
Submitted
Kathleen
Goodman
3
BC Hydro and Power
Authority
Pat Harrington
Affirmative
N/A
3
Beaches Energy
Services
Steven Lancaster
Negative
Third-Party
Comments
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Third-Party
Comments
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Negative
Third-Party
Comments
3
City of Leesburg
Chris Adkins
Negative
Third-Party
Comments
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
Affirmative
N/A
3
Cleco Corporation
Michelle Corley
None
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Kent Kujala
Negative
Third-Party
Comments
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Affirmative
N/A
Darnez
Gresham
Bill Hughes
Louis Guidry
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Negative
Comments
Submitted
3
Georgia System
Operations
Corporation
Scott McGough
Negative
Comments
Submitted
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Negative
Comments
Submitted
3
Great River Energy
Brian Glover
Negative
Third-Party
Comments
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
Mace Hunter
Negative
Third-Party
Comments
3
Lincoln Electric
System
Jason Fortik
Negative
Third-Party
Comments
3
Los Angeles
Department of Water
and Power
Mike Anctil
None
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
None
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
Third-Party
Comments
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public
Power District
Tony Eddleman
None
N/A
Douglas Webb
Oshani
Pathirane
3
New York Power
Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
None
N/A
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
None
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Abstain
N/A
3
PHI - Potomac
Electric Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Negative
Third-Party
Comments
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Negative
Comments
Submitted
3
Sacramento
Municipal Utility
District
Rachel Moore
Joe Tarantino
Affirmative
N/A
3
Salt River Project
John Coggins
Chris Janick
Affirmative
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power
Electric Cooperative
Jeff Neas
None
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Negative
Comments
Submitted
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
Affirmative
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
None
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
Jim Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Negative
Comments
Submitted
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Affirmative
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Negative
Third-Party
Comments
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Negative
Third-Party
Comments
4
City of Redding
Nick Zettel
4
CMS Energy Consumers Energy
Company
4
Bill Hughes
Affirmative
N/A
Julie Hegedus
Affirmative
N/A
DTE Energy - Detroit
Edison Company
Daniel Herring
Negative
Third-Party
Comments
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Negative
Comments
Submitted
4
Georgia System
Operations
Corporation
Guy Andrews
Negative
Comments
Submitted
4
Illinois Municipal
Electric Agency
Bob Thomas
Negative
Comments
Submitted
4
Keys Energy Services
Stanley Rzad
Negative
Third-Party
Comments
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Negative
Third-Party
Comments
4
Modesto Irrigation
District
Spencer Tacke
None
N/A
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Abstain
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Steve McElhaney
None
N/A
Joe Tarantino
Association
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
Ameren - Ameren
Missouri
Sam Dwyer
Negative
Third-Party
Comments
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
Affirmative
N/A
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista
Corporation
Steve Wenke
None
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Abstain
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Third-Party
Comments
5
Calpine Corporation
Hamid Zakery
Abstain
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Negative
Third-Party
Comments
5
City and County of
San Francisco
Daniel Mason
Abstain
N/A
5
City of Independence,
Jim Nail
Affirmative
N/A
Power and Light
Department
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
None
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
Affirmative
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
Affirmative
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Affirmative
N/A
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Negative
Third-Party
Comments
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
None
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Affirmative
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal
Power Agency
David Schumann
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power
and Light Co.
Harold Wyble
Negative
Comments
Submitted
5
Great River Energy
Preston Walsh
Negative
Third-Party
Comments
5
Hydro-Qu?bec
Production
Roger Dufresne
Negative
Comments
Submitted
Douglas Webb
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Negative
Third-Party
Comments
5
Los Angeles
Department of Water
and Power
Kenneth Silver
None
N/A
5
Lower Colorado River
Authority
Dixie Wells
Affirmative
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
None
N/A
5
MEAG Power
Steven Grego
None
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Third-Party
Comments
5
NB Power
Corporation
Rob Vance
Affirmative
N/A
5
Nebraska Public
Power District
Don Schmit
Negative
Third-Party
Comments
5
New York Power
Authority
Wayne Sipperly
None
N/A
5
NextEra Energy
Allen Schriver
Negative
Comments
Submitted
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
Negative
Third-Party
Comments
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Abstain
N/A
5
Oglethorpe Power
Corporation
Bernard Johnson
Negative
Third-Party
Comments
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
Scott Miller
5
OTP - Otter Tail
Power Company
Cathy Fogale
Negative
Third-Party
Comments
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
Affirmative
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Negative
Comments
Submitted
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Edward Magic
Affirmative
N/A
5
Seattle City Light
Mike Haynes
Abstain
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Negative
Comments
Submitted
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation,
LLC
Donald Lock
Affirmative
N/A
5
Tallahassee Electric
(City of Tallahassee,
Karen Webb
Affirmative
N/A
Joe Tarantino
FL)
5
TECO - Tampa
Electric Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
Brandy Spraker
Affirmative
N/A
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Affirmative
N/A
5
Xcel Energy, Inc.
Mark Castagneri
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Negative
Comments
Submitted
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
None
N/A
6
Colorado Springs
Utilities
Shannon Fair
Negative
Comments
Submitted
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Affirmative
N/A
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Negative
Comments
Submitted
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Richard Montgomery
None
N/A
Richard Hoag
Power Agency
6
Florida Municipal
Power Pool
Tom Reedy
Negative
Comments
Submitted
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Negative
Comments
Submitted
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Negative
Third-Party
Comments
6
Lower Colorado River
Authority
Michael Shaw
Affirmative
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
Third-Party
Comments
6
New York Power
Authority
Shivaz Chopra
None
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Third-Party
Comments
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
None
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
None
N/A
6
Platte River Power
Authority
Carol Ballantine
Affirmative
N/A
6
Portland General
Electric Co.
Shawn Davis
Affirmative
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Negative
Third-Party
Comments
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
Nick Braden
Joe Tarantino
6
Salt River Project
William Abraham
6
Santee Cooper
6
Chris Janick
Affirmative
N/A
Michael Brown
Affirmative
N/A
Seattle City Light
Charles Freeman
Abstain
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Negative
Third-Party
Comments
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Affirmative
N/A
6
TECO - Tampa
Electric Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
None
N/A
6
Westar Energy
Tiffany Lake
Affirmative
N/A
6
Xcel Energy, Inc.
Peter Colussy
Negative
Comments
Submitted
7
Exxon Mobil
Jay Barnett
Abstain
N/A
7
Luminant Mining
Company LLC
Stewart Rake
Affirmative
N/A
8
David Kiguel
David Kiguel
Negative
Third-Party
Comments
8
Massachusetts
Attorney General
Frederick Plett
Affirmative
N/A
9
City of Vero Beach
Ginny Beigel
Negative
Third-Party
Comments
9
Commonwealth of
Massachusetts
Donald Nelson
Abstain
N/A
Department of Public
Utilities
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony Jablonski
Abstain
N/A
10
SERC Reliability
Corporation
Joe Spencer
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/27)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3
Non-binding Poll IN 1 NB
Voting Start Date: 9/4/2015 12:01:00 AM
Voting End Date: 9/14/2015 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 225
Total Ballot Pool: 269
Quorum: 83.64
Weighted Segment Value: 56.9
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
68
1
28
0.651
15
0.349
0
14
11
Segment:
2
8
0.6
1
0.1
5
0.5
0
2
0
Segment:
3
63
1
22
0.564
17
0.436
0
10
14
Segment:
4
20
1
8
0.533
7
0.467
0
3
2
Segment:
5
60
1
21
0.568
16
0.432
0
12
11
Segment:
6
37
1
15
0.577
11
0.423
0
5
6
Segment:
7
2
0.1
1
0.1
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment: 1
0.1
0
0
© 2016
NERC
Ver
3.0.0.0
Machine
Name:
ERODVSBSWB02
8
Segment:
9
2
0.1
0
0
1
0.1
0
1
0
Segment:
10
8
0.5
3
0.3
2
0.2
0
3
0
Totals:
269
6.4
99
3.393
75
3.007
0
51
44
BALLOT POOL MEMBERS
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Ameren - Ameren
Services
Eric Scott
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Abstain
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Abstain
N/A
1
Beaches Energy
Services
Don Cuevas
Negative
Comments
Submitted
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Comments
Submitted
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
None
N/A
1
Cleco Corporation
John Lindsey
None
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Affirmative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Abstain
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
None
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Negative
Comments
Submitted
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
Negative
Comments
Submitted
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
Abstain
N/A
1
Hydro-Qu?bec
TransEnergie
Martin Boisvert
Negative
Comments
Submitted
Louis Guidry
Douglas Webb
1
IDACORP - Idaho
Power Company
Molly Devine
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
Affirmative
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
None
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
Nebraska Public
Power District
Jamison Cawley
Abstain
N/A
1
New York Power
Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Negative
Comments
Submitted
1
NiSource - Northern
Indiana Public
Service Co.
Julaine Dyke
Negative
Comments
Submitted
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Abstain
N/A
1
Oncor Electric
Delivery
Rod Kinard
Affirmative
N/A
Scott Miller
Tammy Porter
1
Peak Reliability
Jared Shakespeare
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Abstain
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
Abstain
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Negative
Comments
Submitted
1
Sacramento
Municipal Utility
District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
None
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
None
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Negative
Comments
Submitted
1
Southwest
Transmission
John Shaver
Negative
Comments
Submitted
Joe Tarantino
Bret Galbraith
Cooperative, Inc.
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Negative
Comments
Submitted
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
Affirmative
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Abstain
N/A
2
California ISO
Richard Vine
Negative
Comments
Submitted
2
Electric Reliability
Council of Texas, Inc.
christina bigelow
Negative
Comments
Submitted
2
Herb Schrayshuen
Herb Schrayshuen
Negative
Comments
Submitted
2
Independent
Electricity System
Operator
Leonard Kula
Negative
Comments
Submitted
2
Midcontinent ISO,
Inc.
Terry BIlke
Negative
Comments
Submitted
2
New York
Independent System
Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren
David Jendras
Abstain
N/A
Services
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
Abstain
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Lisa Martin
Affirmative
N/A
3
Avista - Avista
Corporation
Scott Kinney
None
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Pat Harrington
Abstain
N/A
3
Beaches Energy
Services
Steven Lancaster
Negative
Comments
Submitted
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Comments
Submitted
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Negative
Comments
Submitted
3
City of Leesburg
Chris Adkins
Negative
Comments
Submitted
3
Clark Public Utilities
Jack Stamper
Affirmative
N/A
3
Cleco Corporation
Michelle Corley
None
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
Darnez
Gresham
Louis Guidry
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Kent Kujala
Negative
Comments
Submitted
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Negative
Comments
Submitted
3
Georgia System
Operations
Corporation
Scott McGough
Negative
Comments
Submitted
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Negative
Comments
Submitted
3
Great River Energy
Brian Glover
Negative
Comments
Submitted
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
Lakeland Electric
Mace Hunter
Negative
Comments
Submitted
3
Lincoln Electric
System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
None
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
Douglas Webb
Oshani
Pathirane
3
MEAG Power
Roger Brand
3
Muscatine Power and
Water
3
Scott Miller
None
N/A
Seth Shoemaker
Negative
Comments
Submitted
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public
Power District
Tony Eddleman
None
N/A
3
New York Power
Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
None
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Abstain
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
None
N/A
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Negative
Comments
Submitted
3
Sacramento
Municipal Utility
District
Rachel Moore
Joe Tarantino
Affirmative
N/A
3
Salt River Project
John Coggins
Chris Janick
Affirmative
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Negative
Comments
Submitted
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Negative
Comments
Submitted
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Abstain
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
None
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Affirmative
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Negative
Comments
Submitted
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Negative
Comments
Submitted
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Negative
Comments
Submitted
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Carol Chinn
Negative
Comments
Power Agency
Submitted
4
Georgia System
Operations
Corporation
Guy Andrews
Negative
Comments
Submitted
4
Illinois Municipal
Electric Agency
Bob Thomas
Abstain
N/A
4
Keys Energy Services
Stanley Rzad
Negative
Comments
Submitted
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Abstain
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Negative
Comments
Submitted
4
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Abstain
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista
Corporation
Steve Wenke
None
N/A
Joe Tarantino
5
Basin Electric Power
Cooperative
Mike Kraft
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Clement Ma
Abstain
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Abstain
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Comments
Submitted
5
Calpine Corporation
Hamid Zakery
Abstain
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Negative
Comments
Submitted
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
None
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
Affirmative
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
Affirmative
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Affirmative
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Negative
Comments
Submitted
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
None
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
FirstEnergy -
Robert Loy
Affirmative
N/A
Louis Guidry
FirstEnergy Solutions
5
Florida Municipal
Power Agency
David Schumann
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power
and Light Co.
Harold Wyble
Negative
Comments
Submitted
5
Great River Energy
Preston Walsh
Negative
Comments
Submitted
5
Hydro-Qu?bec
Production
Roger Dufresne
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
None
N/A
5
Lower Colorado River
Authority
Dixie Wells
Affirmative
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
None
N/A
5
MEAG Power
Steven Grego
None
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Comments
Submitted
5
Nebraska Public
Power District
Don Schmit
Abstain
N/A
5
New York Power
Authority
Wayne Sipperly
None
N/A
5
NextEra Energy
Allen Schriver
Negative
Comments
Submitted
5
NiSource - Northern
Indiana Public
Michael Melvin
Negative
Comments
Submitted
Douglas Webb
Scott Miller
Service Co.
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Abstain
N/A
5
Oglethorpe Power
Corporation
Bernard Johnson
Negative
Comments
Submitted
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Abstain
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
Affirmative
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Negative
Comments
Submitted
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Edward Magic
Affirmative
N/A
5
Seattle City Light
Mike Haynes
Abstain
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Negative
Comments
Submitted
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
Joe Tarantino
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
Tennessee Valley
Authority
Brandy Spraker
Abstain
N/A
5
Westar Energy
stephanie johnson
Affirmative
N/A
5
Xcel Energy, Inc.
Mark Castagneri
Negative
Comments
Submitted
6
Ameren - Ameren
Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
None
N/A
6
Colorado Springs
Utilities
Shannon Fair
Negative
Comments
Submitted
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
None
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Negative
Comments
Submitted
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Negative
Comments
Submitted
6
Great River Energy
Donna Stephenson
Michael
Negative
Comments
Louis Guidry
Richard Hoag
Brytowski
Submitted
6
Lower Colorado River
Authority
Michael Shaw
Affirmative
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
Comments
Submitted
6
New York Power
Authority
Shivaz Chopra
None
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Negative
Comments
Submitted
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
None
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
Comments
Submitted
6
Platte River Power
Authority
Carol Ballantine
Abstain
N/A
6
Portland General
Electric Co.
Shawn Davis
Affirmative
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
None
N/A
6
Sacramento
Municipal Utility
District
Diane Clark
Joe Tarantino
Affirmative
N/A
6
Salt River Project
William Abraham
Chris Janick
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Abstain
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Negative
Comments
Submitted
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Negative
Comments
Submitted
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Affirmative
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Abstain
N/A
6
Westar Energy
Tiffany Lake
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
Abstain
N/A
7
Luminant Mining
Company LLC
Stewart Rake
Affirmative
N/A
8
David Kiguel
David Kiguel
Negative
Comments
Submitted
9
City of Vero Beach
Ginny Beigel
Negative
Comments
Submitted
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Abstain
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
Comments
Submitted
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony Jablonski
Abstain
N/A
10
SERC Reliability
Corporation
Joe Spencer
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Steven Rueckert
Abstain
N/A
Coordinating Council
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Showing 1 to 269 of 269 entries
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Next
Survey Report
Survey Details
Name
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls | BAL-005-1,
BAL-006-3 & FAC-001-3
Description
Start Date
7/30/2015
End Date
9/14/2015
Associated Ballots
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC001-3 IN 1 ST
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC001-3 Non-binding Poll IN 1 NB
Survey Questions
1. The SDT has modified the definition of Automatic Generation Control (AGC). Do you agree that
this modified definition better represents the SDT intent to making resources more inclusive than
just the traditional generation resources? If not, please explain in the comment area below.
Yes
No
2. The SDT has moved the BAL-005-0.2b Requirement R1 to FAC-001 since it provides for
identifying interconnection Facilities and not for calculating Reporting ACE. Do you agree with
moving this requirement into the FAC-001-3 standard? If not, please explain in the comment area
below.
Yes
No
3. The SDT has moved the BAL-006-2 Requirement R3 into BAL-005-3 since this requirement
directly impacts an entity’s ability to calculate an accurate Reporting ACE. Do you agree with
moving this requirement into the proposed BAL-005-1 standard? If not, please explain in the
comment area below.
Yes
No
4. Please provide any issues you have on this draft of the BAL-005-1 standard and a proposed
solution.
5. Please provide any issues you have on the proposed change to the BAL-006-3 standard and a
proposed solution.
6. Please provide any issues you have on the proposed change to the FAC-001-3 standard and a
proposed solution.
Responses By Question
1. The SDT has modified the definition of Automatic Generation Control (AGC). Do you agree
that this modified definition better represents the SDT intent to making resources more inclusive
than just the traditional generation resources? If not, please explain in the comment area below.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
The California ISO supports the comments of the ISO/RTO Council Standards
Review Committee for all questions in this Survey.
Document Name:
Likes:
0
Dislikes:
0
Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Yes
Answer Comment:
We agree it makes AGC more inclusive and understand there was a FERC
directive to make this change, but the directive does not add to reliability.
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
1
DTE Energy - Detroit Edison Company, 5, DePriest Jeffrey
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
Yes
We agree that the modified definition is a step in the right direction. However, the
definition references Demand Response in capital letters. While that concept is
recognized by industry, it officially is not a NERC Glossary Term. We
recommend that SDT rephrase the last sentence of this definition to read
“Resources utilized under AGC may include, but not be limited to, conventional
generation, variable energy resources, energy storage devices, and demand
response resources.”
Document Name:
Likes:
0
Dislikes:
0
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
No
Texas RE does agree that the revised definition is more inclusive. There is a
concern, however, about disregarding asynchronous Tie MWs in the calculation
for Reporting ACE. If a Balancing Authority (BA) has 1000 MWs of generation
and 500 MWS of load with the remaining generation being transferred
asynchronously, how will the ACE equation , and subsequently AGC, work
properly?
With the revised definition of Reporting ACE, it appears the Standard Drafting
Team (SDT) is disregarding single BA Interconnections, such as ERCOT and
Quebec. Texas RE is concerned about the statement “All NERC
Interconnections with multiple Balancing Authority Areas operate using the
principles of Tie-bias (TLB) Control and requirement the use of an ACE equation
similar to the Reporting ACE defined above.” This statement implies that single
BA Interconnections, such as ERCOT and Quebec do not operate using the
principles of TLB and the use of ACE. If not, how does BAL-001 apply? Is
indicating an “alternative” method for a Reporting ACE equation use advocating
regional differences?
Texas RE inquires as to whether it is the SDT’s intent that AGC (as currently
defined in the proposed definition) will be only frequency-based for singlebalancing authority areas.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
Document Name:
No
FMPA supports using the term resources to make the definition more inclusive,
but the capitalized term Demand Response is not in the NERC glossary of terms.
Likes:
0
Dislikes:
0
Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
Yes
PJM finds that the modified definition of AGC is inclusive of more resource types
than only traditional generation resources. However, AGC equipment does not
directly adjust the output of resources, but instead generates and sends control
signals to the resources to change output. PJM suggests the following change to
the definition for clarity:
Automatic Generation Control (AGC): Centrally located equipment that
generates and sends control signals to automatically adjusts resources in a
Balancing Authority Area to help maintain the Reporting ACE in that of a
Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards. Resources utilized under AGC may include, but are not
limited to, conventional generation, variable energy resources, storage devices
and loads acting as resources (such as Demand Response).
Document Name:
Likes:
0
Dislikes:
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
Answer Comment:
Yes
AGC is no longer used in BAL-005-1, therefore HQ questions whether Project
2010-14.2.1 is the best opportunity to revise this definition.
Document Name:
Likes:
0
Dislikes:
0
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Answer Comment:
Yes
The modification is on the correct track to expand the definition.
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
Yes
Duke Energy recommends that the drafting team clarify or state that just
because a term appears in a definition does not make the definition
applicable to said term. For example, the term “Demand Response” appears
in the proposed definition of Automatic Generation Control (AGC), however,
AGC does not adjust Demand Response. Clarification is needed from the
drafting team stating that just because this term appears in the definition,
this doesn’t mean every type of Generating Resource, Load Resource, or
Load reacting as a resource is capable of providing response to an AGC
signal. Just because a term is listed in the definition, doesn’t mean it
should qualify as an example. We suggest the drafting team revise the
language to include “such as qualified demand resources” rather than
“Demand Response” which can mean a lot of different things.
Document Name:
Likes:
0
Dislikes:
0
Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
No
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
No
These comments are submitted on behalf LG&E and KU Energy, LLC
(LG&E/KU). LG&E/KU is registered in the SERC Region for one or more of the
following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, RP, TO, TOP, TP,
and TSP
Comments:
Making a definition “more inclusive” does not make it clearer or better. In fact, an
argument can be made that an “inclusive” definition can become
problematic. The proposed definition includes uneccessary, prescriptive
language on what types of resources may be used for AGC. We are concerned
that the list will raise expectations that VERs, storage devices and Demand
Response resources should be included in an entity’s AGC function. Many
Demand Response programs (such as residential load interruption) are not
compatible with AGC operations and should not be considered as such.
The last sentence of the proposed definition is not necessary, reduces the clarity
of the definition and should be deleted.
Automatic Generation Control (AGC): Centrally located equipment that
generates and sends control signals to automatically adjust resources in a
Balancing Authority Area to help maintain the Reporting ACE in that of a
Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
Document Name:
Likes:
0
Dislikes:
0
Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
No
The use of centrally located equipment, that automatically adjusts, maintain
Reporting ACE, resources utilized under AGC needs to be considered.
There is no justification to link the definition of Automatic Generation Control
(AGC) to a given location.
AGC is not hardware (equipment); AGC is software.
AGC does not “adjust resources” (that is usually accomplished at the resource
itself). AGC “is used to adjust resources”.
AGC is not designed for reporting purposes. AGC is design to assist in the control
of a BA’s balance of its resources to its NERC mandated balancing obligations.
Propose that the definition be revised to:
Automatic Generation Control (AGC): Software designed and used to adjust a
Balancing Authority’s resources to meet the BA’s balancing requirements as
required by applicable NERC Reliability Standards.
BAL-005 being a NERC standard and not one of the many regionally-approved
standards is applicable to all BAs unless the BA is in a region in which the
standard is superseded by a FERC-approved regional standard. Automatic Time
Error Correction is not a part of the FERC-approved standards for all BAs. For
clarity the regionally-approved definition and references to Automatic Time Error
Correction (I ATEC) be deleted and left to an approved regional standard.
Document Name:
Likes:
0
Dislikes:
0
Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
No
The SRC does not agree with the proposed definition of AGC.
The SRC recommends the following definition for AGC:
Automatic Generation Control (AGC): A process designed and used to adjust a
Balancing Authority’s resources to meet the BA’s balancing requirements as
required by applicable NERC Reliability Standards.
See attached for the full text of the comments to Questions 1-6
Document Name:
SRC - 2010-14-2-1 BAL-005.006 FAC-001.docx
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
No
The added sentence at the end of the definition adequately serves the purpose of
clarifying that all “resources” are included rather than just traditional
generators. The change to add the descriptor “Centrally located” when describing
the “equipment” is also problematic. There does not appear to be a stated
justification for making that change and it could introduce issues in interpretation
surrounding redundant systems or sub-systems that could or should be included
in the system that is used for AGC. If there is a reason for continuing to include
the “centrally located” descriptor, we suggest that the SDT clarify the reason.
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
2. The SDT has moved the BAL-005-0.2b Requirement R1 to FAC-001 since it provides for
identifying interconnection Facilities and not for calculating Reporting ACE. Do you agree with
moving this requirement into the FAC-001-3 standard? If not, please explain in the comment area
below.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
No
Answer Comment:
WedonotagreethatFACͲ001isthecorrectstandardtohousethese
obligations.FACͲ001appliestotheinterconnectionofnewfacilities,whilethe
R5,R6&R7RequirementstakenfromBALͲ005Ͳ0.2bapplytoallTransmission,
Generation&Loadfacilities.
Intheeventthatthedraftingteam*is*successfulinmovingtheseobligationsto
FACͲ001,thenewrequirementswillneedtobeclarifiedsothatthe
requirementsapplyonlytonewinterconnectingfacilities(consistentwiththe
spiritoftheotherFACͲ001requirements).Inthatcase,separaterequirements
willstillberequiredelsewheretoapplytoexistingTransmission,Generation&
Loadfacilities.Inaddition,itwouldalsobeincumbentontheTOtoensurethat
thewordingfortheseobligationsareexplicitwithintheirinterconnect
agreementsandthenecessaryinterconnectguidesthatarespecifiedinFACͲ001.
AEP’sdecisiontovotenegativeonthisproposalisdrivenbytheseobjections.
Document Name:
Likes:
0
Dislikes:
0
Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Answer Comment:
No
It is not necessary to move this requirement. The SDT is taking a flawed
requirement and moving it to another location. The requirement should be
improved as follows.
R1.
All generation, transmission, and load operating within an Interconnection
must be included within the metered boundaries of a Balancing Authority Area.
The requirement above was a concept (Control Area Criteria) that was swept into
the V0 standard. The only way to prove that everything is within the metered
bounds of a BA is via Inadvertent Interchange accounting. R1 should be kept asis, the sub-bullets removed and the measure for R1 should be:
M1. The Balancing Authority was unable to agree with an Adjacent Balancing
Authority when performing Inadvertent Interchange accounting and it was found
that the Balancing Authority had an error in its model or tie lines that misstated its
Net Actual Interchange value in its Inadvertent Interchange accounting.
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
See attachment with strikethrough.
It is not necessary to move this requirement. The SDT is taking a flawed
requirement and moving it to another location. The requirement should be
improved as follows.
R1.
All generation, transmission, and load operating within an
Interconnection must be included within the metered boundaries of a
Balancing Authority Area.
R1.1. Each Generator Operator with generation facilities operating in an
Interconnection shall ensure that those generation facilities are included within
the metered boundaries of a Balancing Authority Area.
R1.2. Each Transmission Operator with transmission facilities operating in
an Interconnection shall ensure that those transmission facilities are included
within the metered boundaries of a Balancing Authority Area.
R1.3. Each Load-Serving Entity with load operating in an Interconnection shall
ensure that those loads are included within the metered boundaries of a
Balancing Authority Area.
The requirement above was a concept (Control Area Criteria) that was
swept into the V0 standard. The only way to prove that everything is within
the metered bounds of a BA is via Inadvertent Interchange accounting. R1
should be kept as-is, the sub-bullets removed and the measure for R1
should be:
M1. The Balancing Authority was unable to agree with an Adjacent
Balancing Authority when performing Inadvertent Interchange accounting
and it was found that the Balancing Authority had an error in its model or
tie lines that misstated its Net Actual Interchange value in its Inadvertent
Interchange accounting.
Document Name:
Project 2010-14..2.docx
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
No
It is not necessary to move this requirement. The requirement can be improved
by keeping it where it is and limiting it to:
R1.
All generation, transmission, and load operating within an Interconnection
must be included within the metered boundaries of a Balancing Authority Area.
The requirement is a concept from the NERC Operating Manual (Control Area
Criteria) that was swept into the V0 standard. There is only one way to prove that
everything is within the metered bounds of a BA, that is through Inadvertent
Interchange accounting. Thus the measure for this requirement should be:
M1. The Balancing Authority was unable to agree with an Adjacent Balancing
Authority when performing Inadvertent Interchange accounting and it was found
that the Balancing Authority had an error in its model or tie lines that misstated its
Net Actual Interchange value in its Inadvertent Interchange accounting.
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
No
BAL-005-0.2b R1 should remain where it is, but would be improved by the
removal of the sub Requirements. The only means to prove that everything is
within the metered boudaries of a Balancing Authority is through Inadventent
Interchange accounting.
The revised R1 should read: R1.
All generation, transmission, and load
operating within an Interconnection must be included within the metered
boundaries of a Balancing Authority Area.
The measure M1 should read: M1. The Balancing Authority was unable to agree
with an Adjacent Balancing Authority when performing Inadvertent Interchange
accounting and it was found that the Balancing Authority had an error in its model
or tie lines that misstate its Nets Actual Interchange value in its Inadventent
Interchange accounting.
Document Name:
Likes:
0
Dislikes:
0
Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
No
While there is agreement with the removal of R1 from BAL-005-0.2b, the insertion
of 4.1.3, and R5-R7 into FAC-001-2 is not required. Notification of an entities
inclusion within a Balancing Authority’s metered boundaries can be accomplished
through the NERC Rules of Procedure, Section 500, FAC-001-2, proposed
standard TOP-003-3 and existing standard IRO-010-2. For example, sufficient
latitude exists within FAC-001-2 as approved, for the TO to provide notification
to “those responsible for the reliability of the affected system(s) of new or
materially modified existing interconnections.” Through this requirement, the
TO can provide a list of new or modified facilities (such as new or modified load,
transmission and generator connections) to the TOP, BA and RC.
Document Name:
Likes:
0
Dislikes:
0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Answer Comment:
No
As worded, we do not believe these requirements are appropriate for FAC-0013. Since FAC-001-3 applies to documented Facility interconnection
requirements, it would be more appropriate to require that the documented
interconnection requirements contain language stating that transmission,
generation and end-user interconnected Facilities must be located within the
Balancing Authority Area’s metered boundaries. This could be accomplished by
adding R3.3 stating “Procedures for ensuring that transmission Facilities,
generation Facilities and end-user Facilities are within the Balancing Authority
Area’s metered boundaries.” The requirement to verify that existing facilities are
located with the metered boundaries of a Balancing Authority Area is most
appropriately assigned to the TOP, and not to the TO, GO and the LSE.
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
No
1. We concur that the intent of BAL-005-0.2b Requirement R1 provides for
identification of Interconnection Facilities and not for the calculation of
Reporting ACE. We question if the SDT followed the recommendations
of the Project 2010-14.2 BAL Standards PRT to “explore if the role of the
TOP would appropriately cover the loads interconnected to that TOP
such that the LSE requirement may not be necessary.” We ask the SDT
to provide rationale for the proposed FAC-001-3 standard to explain their
conclusion on why they continue to list the LSE as an applicable
entity. We remind the SDT that the retirement of the LSE is pending
FERC approval through the Risk-Based Registration (RBR) initiative. We
do not understand why the SDT feels like the LSE has a reliability role,
when the ERO continues to argue that the LSE is primarily focused on
commercial activities and other entities, such as the TOP, would continue
to meet reliability needs without the LSE. We strongly recommend that
the drafting team remove the LSE from the applicability section.
2. As listed within this project’s SAR, the Project 2010-14.2 BAL Standards
PRT “believes that the requirements to identify the applicable BA should
perhaps be in the interconnection agreements (via FERC’s OATT or
NAESB, for example),” we believe these requirements already do. Many
other reliability requirements in the TOP and IRO standards support the
identification of Interconnection Facilities through data modeling and
specifications. For example, TOP-003-3 R4 identifies that “each
Balancing Authority shall distribute its data specification to entities that
have data required by the Balancing Authority’s analysis functions and
Real time monitoring.” If a BA needs information regarding a particular
load, generation resource, or transmission line operating within its BA
Area, based on this requirement, would they not “identify” the correct
entity to send their specification? Furthermore, NERC has spent
significant time and resources on the development of the BES definition
and the removal of the LSE from its functional model. These efforts were
accomplished to focus on entities and facilities that posed a significant
risk to BES reliability. The SDT has already identified that the intent of
these requirements is not for the calculation of Reporting ACE and only
the identification of entities. Moreover, if a generation resource,
transmission line, or load is not properly accounted for in the calculation
of Reporting ACE, Inadvertent Interchange will result and the BA would
investigate to correct the discrepancy, as a best practice,
accordingly. We recommend the SDT remove these requirements from
the proposed draft standards.
Document Name:
Likes:
0
Dislikes:
0
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
No
First, a quick review of the Standards shows there is no other specific
requirement to ensure a facility is in a metered boundry or telemtery is provided to
a RC, BA, or TOP. This requirement is to ensure that a load or generator is
metered and communicated to BA for BA function. It is just as important that line
metering is reported to TOP and RC, yet there is no FAC requirement to install
metering and telemetry. For TOP and RC, there is TOP-03 and IRO-010 with a
data specification and process to deliver data.
Second, FAC-001 is about developing a single document for one-time use by an
interconnecting entity to know what is required to complete an interconnection.
The proposed change creates an ongoing requirement to confoirm that the
interconection is in the metered boundaries ofthe BA. The proposed requirement
is not consistenent with FAC-001. A consistent approach to FAC-001 is to
require that the requirements address the metering required to facilitate the BA
function, but this is already impleied in the current FAC-001-2 standard.
Balancing is becoming a complicated function as compared to the Version 0
days. The BA should have its own data specification standard similar to TOP-003
or IRO-010. In the alternative these requirements should be retired, with the
comment thatthe requirement is implied already in FAc-001-2 and the Technical
and Guideline section of FAC-001-2 will be updated to include a specific
explanation of including interconnection in BA metered boundary.
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
No
Texas RE noticed that the Load-Serving Entity (LSE) function was added to the
FAC-001-3 applicability but is not mentioned in the Evidence Retention section.
Texas RE noticed the term, “Transmission Facilities” is capitalized in R5 but not in
R1.2. The term “Transmission Facilities” is not a defined term in the NERC
glossary so it could cause confusion if capitalized.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
No
Given the stongly suppported rationale for deactivating the LSE registration
function under the Risk-Based Registration initiative, Requirement 1.3 of BAL005-0.2b should not be moved to FAC-001-3 as Requirement 7. The necessity of
retaining this language for reliability purposes should be reconsidered. [Has there
ever been a situation where Load was not within a BA metered boundary?] If this
language is needed for reliability, an alternate functional entity should be
identified.
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Answer Comment:
No
Ameren supports MISO's comments for this question
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
No
FMPA believes these requirements should be retired on the basis that they are
covered by the data specification requirements of Board approved TOP-003-3.
While it may be appropriate to include the concept of meters and BA metered
boundaries in Facility interconnection requirements, as currently worded the
proposed requirements do not fit with the purpose or applicability of FAC-001.
Document Name:
Likes:
0
Dislikes:
0
Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
No
With moving BAL-005-0.2b R1 to FAC-001 R5 and R6, the requirement has
shifted from being a Generator and Transmission Operator function to a
Generator and Transmission Owner function. PJM questions and considers
consequences with this change. PJM seeks clarity on the following topics:
Generation Owners, Transmission Owners, and Load-Serving Entities have no
requirement to supply the Balancing Authority with data that affects the ACE
calculation. PJM proposes the following changes to FAC-001 R5, R6, and R7:
R5. Each Transmission Owner with transmission Facilities operating in an
Interconnection shall confirm that each transmission Facility is within a Balancing
Authority Area’s metered boundaries. The Transmission Owner shall coordinate
any changes caused to the ACE due to each transmission Facility with the
impacted Balancing Authorities.
R6. Each Generator Owner with generation Facilities operating in an
Interconnection shall confirm that each generation Facility is within a Balancing
Authority Area’s metered boundaries. The Generation Owner shall coordinate any
changes caused to the ACE due to each generation Facility with impacted
Balancing Authorities.
R7. Each Load-Serving Entity with Load operating in an Interconnection shall
confirm that each Load is within a Balancing Authority Area’s metered
boundaries. The Load-Serving Entity shall coordinate changes caused to the ACE
due to each Load with impacted Balancing Authorities.
Since Reporting ACE is made up of many components, including Net Actual
Interchange (NIA), Balancing Authorities will be dependent on the Generator
Owners, Transmission Owners, and Load-Serving Entities for this data. When
ACE is impacted by the identified Interconnection Facilities, how should Reporting
ACE be addressed by the Balancing Authority or Reliability Coordinator? If a
Generator, Transmission Owner, or load-Serving Entity fail to confirm that each of
their Facilities are within the Balancing Authority Area’s metered boundaries, is
the affected Balancing Authority responsible for calculating an accurate Reporting
ACE?
What effects will this have on R5? Will the Balancing Authority be aware data
from the Generator Owner or Transmission Owner are missing or invalid if the
Generator Owner or Transmission Owner have not confirmed it?
Document Name:
Likes:
0
Dislikes:
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
Answer Comment:
No
FAC-001 is about Facility Interconnection Requirements. In the application
guidelines of FAC-001-2, it is mentioned that these requirements include metering
and telecommunications and as such could be interpreted to already include a
requirement of metering to the BA. Meeting of facility interconnection
requirements however is the purpose of FAC-002-1.
Therefore 2 options are available:
1. Modify the purpose of FAC-001 to include the GO, TO and LSE,DP or
end-user meeting with facility interconnection requirements (whereas
presently the purpose is only to make these requirements available) and
add in section B, requirements for the GO, TO and LSE,DP or end-user
to comply with all requirements set out in R1 thru R4 (not only with the
requirement of being within a BA’s metered boundaries as is the case
with Project 2010-14.2.1 proposal). Revise purpose of FAC-002-1 so that
it addresses coordination studies rather than meeting facility connection
and performance requirements.
2. Change the title of FAC-002 which presently is a bit at odds with its
purpose and add requirements for the GO, TO and LSE,DP or end-user
to comply with all requirements set out in FAC-001.
Document Name:
Likes:
0
Dislikes:
0
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Answer Comment:
No
As worded, we do not believe these requirements are appropriate for FAC-0013. Since FAC-001-3 applies to documented Facility interconnection
requirements, it would be more appropriate to require that the documented
interconnection requirements contain language stating that transmission,
generation and end-user interconnected Facilities must be located within the
Balancing Authority Area’s metered boundaries. This could be accomplished by
adding R3.3 stating “Procedures for ensuring that transmission Facilities,
generation Facilities and end-user Facilities are within the Balancing Authority
Area’s metered boundaries.” The requirement to verify that existing facilities are
located with the metered boundaries of a Balancing Authority Area is most
appropriately assigned to the TOP, and not to the TO, GO and the LSE.
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
Yes
Duke Energy requests further clarification on how the drafting team
anticipates an entity will be required to demonstrate compliance with R5. As
written, it does not appear that the proposed Requirements and Measures
are in alignment. Currently, the requirements state that an entity (TO, GO,
LSE) must confirm that a Facility is within a Balancing Authority Area’s
Metered Boundary, however, the measure suggests that an entity should
point to a procedure to demonstrate compliance with R5, R6, and R7. We
suggest that the drafting team revise the Measures to better align with what
is being asked in the requirements, perhaps stating that an attestation letter
from the BA would be adequate to demonstrate confirmation that an entity’s
Facility is within a BA Area’s Metered Boundary.
Document Name:
Likes:
0
Dislikes:
0
Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
Answer Comment:
No
As worded, we do not believe that BAL-005-0.2b Requirement R1 is appropriate
for FAC-001-3. Since FAC-001-3 applies to documented Facility interconnection
requirements, it would be more appropriate to require that the documented
interconnection requirements contain language stating that transmission,
generation and end-user interconnected Facilities must be located within the
Balancing Authority Area’s metered boundaries. This could be accomplished by
adding R3.3 stating “Procedures for ensuring that transmission Facilities,
generation Facilities and end-user Facilities are within the Balancing Authority
Area’s metered boundaries.” The requirement to verify that existing facilities are
located with the metered boundaries of a Balancing Authority Area is most
appropriately assigned to the TOP, and not to the TO, GO and the LSE.
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Answer Comment:
No
KCP&L believes moving BAL-005-02.b R1 to FAC-001 should be rejected; it
is an attempt to shoe-horn Requirements into an unrelated Standard, or, at
best, marginally related Standard.
The FAC-001 Standard relates to entities seeking to interconnect with the
Bulk Electric System. The Proposed FAC-001-3 and its predecessor
versions’ Purpose declaration state, "To avoid adverse impacts on the
reliability of the Bulk Electric System, Transmission Owners and applicable
Generator Owners must document and make Facility interconnection
requirements available so that entities seeking to interconnect will have the
necessary information."
It is unclear how Transmission Owners, Generation Owners, and LoadServing Entities confirming they are within a Balancing Authority’s metered
boundaries relate to Generator Owners seeking interconnection with the
Bulk Electric System. The FAC-001 Standard relates to new equipment
planned to interconnect with the Bulk Electric System while BAL-005-02.b
R1 relates to current and operational interconnections.
Additionally, the SAR discusses moving the TOP, LSE, and GOP from BAL005-02.b (See SAR, pp. 4-5) to the FAC Standards. It is unclear where the
TOP duties under R1 landed. It didn’t land in FAC-001. Granted, the SAR is a
framework and not binding, the language suggests the SDT was uncertain
where to "put" the R1 Requirement. However, the Proposed FAC-001-3 R5
Violation Severity Level states, "The Transmission Operators with
Transmission Facilities operating in an Interconnection…" In consideration
of the VSL language and the proposed FAC-001-3 not expressly applicable
to Transmission Operators, KCP&L is concerned that moving BAL-005-02.b
R1 to FAC-001, creates an unstated duty for Transmission Operators.
Furthermore, the Proposed FAC-001-3 Purpose declaration is reiterated in
Applicability Sec. 4.1.2.1., "Generator Owner with a fully executed
Agreement to conduct a study on the reliability impact of interconnecting a
third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission system."
The FAC-001 Standard relates to new interconnects to the Bulk Electric
System and should not be used as a landing pad for BAL-005 Requirements
that no longer are relevant to BAL-005. KCP&L does not object to moving
BAL-005 R1 to another Standard, but FAC-001 is not the appropriate
Standard and the proposed changes should be reconsidered.
Finally, in the event the changes to FAC-001-3 R5, R6, and R7 are endorsed
by the stakeholders, KCP&L would ask language be added to FAC-001-3 to
highlight it is applicable to new facilities, including the facilities identified in
R5, R6, and R7.
Document Name:
Likes:
0
Dislikes:
0
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Answer Comment:
Yes
We agree with moving BAL-005-0.2b Requirement R1 to FAC-001
standard. However, given the likely retirement of the LSE functional role
consideration should be given in the SAR to making the requirement applicable to
the DP functional entity role.
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
No
Load Serving Entity (LSE) function: NERC provided FERC with justification to
retire BAL-005-0.2b Part R1.3 for the LSE function (LSE function
deregistration). Adding LSE requirements to FAC-001 does not appear to align
with NERC’s justification and the intent to retire BAL-005-0.2b R1.3.
FAC-001 Table of Compliance Elements: R5 and R6 reference Transmission
Operator and Generation Operator, instead of Transmission Owner and
Generator Owner.
The Purpose of FAC-001 is to “…make Facility interconnection requirements
available so that entities seeking to interconnect will have the necessary
information.” Adding requirements to FAC-001 regarding metered boundaries
appears to be misplaced. The proposed additions are ongoing requirements to
confirm the metering of transmission facilities. The use of the word “confirm” is
not the same as to establish the interconnection requirements.
Document Name:
Likes:
1
Dislikes:
0
Hydro One Networks, Inc., 1, Farahbakhsh Payam
Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
No
(1) FAC-001-2 was revised in 2013 to eliminate any requirements that were not
necessary for reliability according to FERC paragraph 81 directions. As a member
of the FAC-001-2 SDT charged with this task, GTC along with the other members
followed the directives of FERC and retained only the requirements necessary for
system reliability. As such 14 sub-requirements in FAC -001 were removed
including a requirement for metering and telecommunication.
Although GTC sees a merit in ensuring that the Area Control Error is calculated
properly, GTC believes that the proposed requirements (FAC-001-3-R5, R6 and
R7) does not resolve or address a reliability concern and would violate paragraph
81 criteria.
Moreover GTC believe that requirements FAC-001-3-R5, R6 and R7 address
specific needs for operating the system and therefore belong and already are
included in Operations Standards such as TOP and IRO and not a Planning
Standard associated with Facility interconnection Requirements.
(2) As listed within this project’s SAR, the Project 2010-14.2 BAL Standards
PRT “believes that the requirements to identify the applicable BA should perhaps
be in the interconnection agreements (via FERC’s OATT or NAESB, for
example),” we believe these requirements already do. Many other reliability
requirements in the TOP and IRO standards support the identification of
Interconnection Facilities through data modeling and specifications. For example,
TOP-003-3 R4 identifies that “each Balancing Authority shall distribute its data
specification to entities that have data required by the Balancing Authority’s
analysis functions and Real time monitoring.” TOP-003-3 applies to the same
entities listed in the draft requirements.
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Answer Comment:
No
We appreciate the work by the SDT, but do not agree with moving BAL-005-0.2b
Requirement R1 to FAC-001-3 Requirements R5, R6, and R7. At this time, the
way the BAL-005 requirement R1 reads it poses to be more of an accounting
issue versus a reliability issue. One alternative solution is to remove the language
from this standard (FAC-001-3) and include it in the Application Guidelines
section.
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
No
The SRC supports deleting the R1 requirements in BAL-005-0.2b, and
recommends placing the obligation in a certification requirement.
See file attached to Question 1 for the full text of the comments to Question
2
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Answer Comment:
No
The FAC-001 standard is used to facilitate interconnection requirements for those
entities seeking interconnection into the BES. In the draft FAC-001-3
Requirements R5-R7 the language speaks to those who entities who are already
operating in an interconnection and therefore does not fit the purpose of this
standard. The FAC-001 standard cannot be used to enforce R5 –R7 for those
facilities that already exist.
The LSE function should not be included in the FAC-001 standard and therefore
R7 should be removed in its entirety from the draft. In R7, it is not clear if the LSE,
TO, or GO will be required to address this in their interconnection requirements.
There is no requirement for an LSE to have documented facility interconnection
requirements.
To truly make this consistent with the purpose of the FAC-001 standard the
wording should be revised to address the documented facility interconnection
requirements. The draft standard should require that the TO & Applicable GO
facility interconnection requirements address BAA metered bounds for those
entities seeking interconnection. The entities seeking interconnection should
determine their operating area and therefore BAA metered bounds from their
desired interconnection location.
CSU is of the opinion that these requirements belong in the INT or TOP family of
Standards.
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
No
These requirements do not rise to the level of needing a continuously audited
Reliability Standard. Once a facility is interconnected and certified, then the
inclusion within a BA’s metered bounds should be verified at that time. There
should not be a need for continuing certification that it remains within the metered
bounds. The requirements as stated only result in administrative efforts and are
an exercise in submitting attestations.
One suggestion would be to simply add a sub-requirement that the Transmission
Owner’s Interconnection Requirements (FAC-001-3 R1) must include a
requirement that all interconnected facilities must be demonstrated to be within a
Balancing Authority’s metered boundaries. Then there would be no need for the
new, proposed R5-R7. This puts the compliance effort into ensuring the facility is
metered properly upon interconnection – to satisfy the TO Facility Interconnection
Requirements – rather than an ongoing verification that the facilities continue to
be within the metered bounds.
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
No
Reclamation recommends that the drafting team propose to retire BAL-005-0.2b
R1 instead of moving the requirement into FAC-001-3. Reclamation does not
believe that the drafting team has addressed the Periodic Review Team’s
recommendation to identify “what is needed for ensuring facilities are within a
Balancing Authority Area prior to MW being generated or consumed.” Like the
existing requirement, the proposed requirement does not mention verifying that
facilities are within the metered boundaries of a Balancing Authority Area “prior to
transmission operation, resource operation, or load being served.” Therefore, the
proposed requirement perpetuates a paperwork burden that costs staff time and
resources of Generator Operators, Transmission Operators, and Load Serving
Entities with longstanding arrangements with their host Balancing
Authority. Registered Entities acquiring letters to confirm that they are in the
metered boundaries of a Balancing Authority Area provides no benefit to system
reliability.
Document Name:
Likes:
0
Dislikes:
0
3. The SDT has moved the BAL-006-2 Requirement R3 into BAL-005-3 since this requirement
directly impacts an entity’s ability to calculate an accurate Reporting ACE. Do you agree with
moving this requirement into the proposed BAL-005-1 standard? If not, please explain in the
comment area below.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
No
Answer Comment:
MWHr meters are for Inadvertent Interchange accounting. Making this
change will confuse the issue and will add unnecessary obligations. As
long as the two BAs use common metering, any minor error in reporting
ACE is contained between them and has no impact on the Interconnection
as a whole.
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
No
MWHr meters are for Inadvertent Interchange accounting. There are already
other requirements proposed that deal with making sure ACE is realatively
accurate. Additionally, as long as adjacent BAs use common metering, any minor
error in reporting ACE is contained between them and has no impact on the
Interconnection as a whole.
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
No
MWHr meters are for Inadventent Interchange accounting. Making the proposed
change could lead to confustion and unnecessary obligations. If the two BAs use
common metering, any minor error in ACE reporting is contained and would have
no impact on the Interconnection as a whole.
Document Name:
Likes:
0
Dislikes:
0
Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
Yes
We concur with the SDT’s recommendation, as BAL-005-1 addresses more
proactive and real-time AGC operations while BAL-006 addresses more after-thefact.
Document Name:
Likes:
0
Dislikes:
0
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
No
Texas RE noticed there is no redline for BAL-005-1. Redlines are helpful in
reviewing revisions.
Texas RE noticed BAL-006-2 R3 has the phrase “with readings provided hourly”
(emphasis added) which, dictates a timing aspect. BAL-005-1 R1 has the phrase
“to determine hourly megawatt-hour values” but does not have a time aspect
specifically required. Texas RE inquires whether this was the intent of the SDT
(and Texas RE is aware of the expected historical practice of hourly
communications between entities).
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Answer Comment:
No
Ameren supports MISO's comments for this question
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
Document Name:
No
FMPA agrees removing R3 from BAL-006, but it seems to have created
duplicative requirements in BAL-005. Requirements R1 and R8 should be
combined.
Likes:
0
Dislikes:
0
Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
No
The standard states that the purpose is for acquiring data to calculate Reporting
ACE. R1 does not fall under that category as it is currently written. It states its
purpose is to determine MWh values. PJM suggests the following change to the
R1 to align with the purpose of BAL-005:
R1. Each Balancing Authority shall ensure that each Tie Line, Pseudo Tie, and
Dynamic Schedule with an Adjacent Balancing Authority is equipped with a
mutually agreed upon time synchronized common source. to determine hourly
megawatt hour values.
While PJM agrees it is important to maintain a requirement to calculate MWh
values for Inadvertent Interchange, PJM suggest this be moved to a NAESB
standard.
Document Name:
Likes:
0
Dislikes:
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
Answer Comment:
No
For the Quebec Interconnection, it makes more sense for metering issues to be in
BAL-006 than BAL-005 since as a single BA asynchronous Interconnection, Net
Interchanges are not calculated in our ACE. However HQ understands that our
situation is exceptional and do not oppose the move of BAL-006-2 R3 to BAL005-1.
Document Name:
Likes:
0
Dislikes:
0
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
Yes
Duke Energy agrees with the move to BAL-005-1, however, we recommend
that the drafting team revise the Measure for R1 to better align with R1.1.
The sub-requirement R1.1 states that megawatt-hour values must be
exchanged between Adjacent Balancing Authorities. The Measure provides
guidance for R1, but does not provide guidance or example of
demonstrating compliance with R1.1. More information is needed to outline
how an entity is expected to demonstrate that the exchange of values took
place, and how often must the exchange take place.
Document Name:
Likes:
0
Dislikes:
0
Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
No
BAL-006-2-R3. Each Balancing Authority shall ensure all of its Balancing Authority Area
interconnection points are equipped with
common megawatt-hour
meters, with readings provided hourly to the control centers of Adjacent
Balancing
Authorities.
Is there a requirement for hourly reporting? What is meant by “common”? Is this
a certification issue, or an Interconnection Agreement issue, or a standard?
Document Name:
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Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
No
Answer Comment:
Document Name:
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0
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0
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
No
The SRC opposes the proposal to move BAL-006-2 Requirement R3 into BAL005-3.
The SRC recommends that BAL-006 be deleted.
See file attached to Question 1 for the full text of the comments to Question
3
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Yes
Answer Comment:
Document Name:
Likes:
0
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0
Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Answer Comment:
N/A
Document Name:
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0
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0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
Yes
The change from BAL-006-2 R3 to BAL-005-1 R1 and R8 seem to be a step in
the right direction. The measures however (BAL-005-1 M1) seems to only require
evidence that a common source was agreed upon, not that the data values were
actually exchanged between Adjacent BA’s in a timely manner. If the intent is
only to ensure a common source was identified, then that should be done in
certification and does not rise to a Reliability Standard.
The need for common megawatt-hour meters between BAs serves only to
account for inadvertent interchange between those entities. Accumulated
inadvertent is not related to real-time reliability. Proposed BAL-005-1 R1 should
be removed.
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Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Yes
Answer Comment:
Document Name:
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0
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0
4. Please provide any issues you have on this draft of the BAL-005-1 standard and a proposed
solution.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
none
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0
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0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Answer Comment:
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0
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0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Answer Comment:
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Likes:
0
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0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
Document Name:
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0
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0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Answer Comment:
a.
Notwithstanding our comments on selected requirements provided
below, as an overall comment we do not believe some of the proposed
requirements belong to a Reliability Standard. We believe
Requirements R2, R4, R5 and R6 are more suited for inclusion in the
Organization Certification Requirement for Balancing Authorities since
these requirements stipulate the capabilities and facilities that need to be in
place to enable a BA to perform its tasks. These are "one-off" requirements
that do not drive continuous behaviors, and they do not require frequent
updates.
b.
Requirement R4: The 99.95% uptime is overly prescriptive and there
does not exist any technical justification. Unless supported by technical
justification, this requirement should be removed. Further addition, the
0.001 Hz “accuracy” requirement is misleading. We suggest to replace
"accuracy" with "resolution" to more properly convey the requirement.
c.
Requirement R5: We agree with the need to provide operating
personnel with accurate information that supports awareness and
calculation of Reportable ACE, but the examples listed places emphasis on
the secondary information as it fails to capture the more important pieces
of information which were listed in the existing BAL-005. We therefore
suggest R5 be revised to:
R5. The Balancing Authority shall make available to the operator
information associated
with Reporting ACE including, but not limited to, real-time values for ACE,
Interconnection
frequency, Net Actual Interchange with each Adjacent Balancing Authority
Area and quality flags indicating missing or invalid data.
d.
R6: As with our comments on R4, the 99.5% uptime is overly
prescriptive and restrictive, and there does not exist any technical
justification. A 99.5% uptime requirement means that all model builds and
software glitches couldn’t exceed 43.8 hours in any given year. This is
overly restrictive. Unless supported by technical justification, this
requirement should be removed.
e.
R7: This requirement is not needed. R1 already stipulates the need to
calculate and hourly megawatt hour values (and Reporting ACE, as we
suggested above); and R4 already stipulates the scan rate. Failure to meet
either requirement will result in a BA being unable to comply with the
standard in which case the BA must develop corrective actions to return to
compliance. Having an explicit operating process to identify and mitigate
errors affecting the scan rate accuracy of data used in the calculation of
Reporting ACE is redundant to the combined requirements in R1 and R4.
We therefore suggest to remove R7.
If for whatever reasons R7 is retained, then the term “Operating Process”
should not be capitalized since it is not a NERC defined term.
f.
R8: This requirement is implied in and redundant with, R1. Suggest
to remove it.
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
See attachment with Strikethrough
The proposed R1 should be shortened and merged with R7. There need not
be mention of “mutually agreed upon” nor “time sychnronized”. AGC and
ACE use real-time values, not hourly values.
BAL-005-1
R1. Each Balancing Authority shall ensure that have a process to operate
to common, accurate each Tie Lines, Pseudo Ties, and Dynamic
Schedules with its an Adjacent Balancing Authorities. is equipped with a
mutually agreed upon time synchronized common source to determine hourly
megawatt hour values
The measure of this requirement is not logs or voice recordings. NSI is
already checked with Inadvertent Accounting and the INT standards. The
process that was proposed in R7 could be the validation and measure for
R1
If the change to R1 above is made, R7 is no longer necessary.
R8 is redundant with when compared to the suggested wording above for
BAL-005-1 R1 and BAL-006 R3.
Document Name:
Project 2010-14..4.pdf
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0
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0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
The proposed R1 should be shortened and merged with R7. There need not be
mention of “mutually agreed upon” nor “time sychnronized”. AGC and ACE use
real-time values, not hourly values.
BAL-005-1
R1. Each Balancing Authority shall have a process to operate to common,
accurate Tie Lines, Pseudo Ties, and Dynamic Schedules with its Adjacent
Balancing Authorities.
The measure of this requirement should not be logs or voice recordings. NSI is
already checked with Inadvertent Accounting and the INT standards. The
process that was proposed in R7 could be the validation and measure for R1
If the change to R1 above is made, R7 is no longer necessary.
R8 is redundant with when compared to the suggested wording above for BAL005-1 R1 and BAL-006 R3
Document Name:
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Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
The proposed R1 should be shortened and merged with R7. No mention of
“mutually agreed upon” nor “time sychnronized” is necessary. AGC and ACE use
real-time values, not hourly values.
We suggest the following:
BAL-005-1
R1. Each Balancing Authority shall have a process to operate to common,
accurate Tie Lines, Pseudo Ties, and Dynamic Schedules with its Adjacent
Balancing Authorities.
The measure of this requirement is not logs or voice recordings. NSI is already
checked with Inadvertent Accounting and the INT standards. The process that
was proposed in R7 could be the validation and measure for R1.
R7 would not be necessary if the change to R1 above is made and R8 would be
redundant with when compared to the suggested wording above for BAL-005-1
R1 and BAL-006 R3.
Document Name:
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0
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0
Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
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0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Answer Comment:
No comments.
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0
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0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
1. We believe Requirement R1 should focus on detection and correction of
a problem rather than a guarantee that a common source is
available. This would better align with a risk-based approach that NERC
is mandating during standard development. We believe this can be
achieved by rephrasing the requirement to read
2.
3.
4.
5.
6.
“Each Balancing Authority shall monitor mutually agreed-upon timesynchronized common source with Adjacent Balancing Authorities to
determine hourly megawatt hour values for each common Tie
Line, Pseudo Tie, and Dynamic Schedule.” We feel that by moving in
this direction, the associated VSLs can be set to more adjustable criteria,
such as the length of time between detection and correction, (e.g. under
30, 60, and 90 days).
We feel the SDT should align the VSLs for R2 to more performancebased criteria. We agree that six-seconds is a reasonable benchmark,
but question if it needs to be categorized as a severe VSL. Instead, we
recommend assigning a sliding time scale to each VSL (e.g. greater than
or equal to 6 seconds, and greater than or equal to 12 seconds, etc.)
In Requirement R3, the BA is expected to notify its RC within 45 minutes
from the beginning of its inability to calculate Reporting ACE. If a BA
encounters multiple instances when it is unable to calculate its Reporting
ACE in a consecutive minute time period, but never haves an instance
that is greater than thirty consecutive minutes, we want to confirm that
the time period for notification begins with the first reportable
instance. We believe this can be accomplished by replacing “an inability”
with “the inability” at end of the requirement to read “…within 45 minutes
of the beginning of the inability to calculate Reporting ACE.”
We believe System Operators should be identified in Requirement R5, as
this is a NERC-defined Glossary Term. Moreover, it does not provide
any ambiguity for auditors and better aligns with those personnel
identified to complete training for reliability-related tasks in Reliability
Standard PER-005-2.
For Requirement R5, we agree with the SDT’s approach that Reporting
ACE can be a primary metric to determine operating actions or
instructions. Furthermore, System Operators should be aware of when
such metrics are based on poor or insufficient data. However, we
disagree with the SDT’s approach taken in the wording of this
requirement. Proof of the existence of a graphical display or dated alarm
log, as mentioned as possible evidence for compliance, will only lead to
confusion on how evidence should be presented. We believe rewording
this requirement to “each Balancing Authority shall monitor the quality of
information used to calculate its own Reporting ACE” achieves the intent
of “making available” sufficient data to System Operators.
We feel the SDT should provide rationale on the need for Requirement
R6. While we agree that “Reporting ACE is an essential measurement of
the BA’s contribution to the reliability of the Interconnection,” we believe a
requirement measuring the availability of a Reporting ACE calculation
system is unnecessary. System Operators, when in distress, likely will
rely on frequency meter measurements and communications with other
Adjacent BAs when Reporting ACE is not available. This proposed
standard already has an availability requirement listed in Requirement
R4, and with a requirement that has a higher availability rate. We believe
7.
8.
9.
10.
11.
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requiring a system be available should be reserved for the ERO Event
Analysis Process, much like SCADA is for RCs and TOPs.
We believe the VSLs criteria for Requirement R7 could be more
performance-based, particularly with how fast the BA took to mitigate
errors affecting the scan rate accuracy of data. We recommend sliding
scale criteria, such as within 15 minutes, within 30 minutes, etc.
In Requirement R8, we believe the requirement should focus on detection
and correction to better align with a risk-based approach. We believe this
can be achieved by rephrasing the requirement to read “Each Balancing
Authority shall use a common source for Tie Lines, Pseudo-Ties, and
Dynamic Schedules with Adjacent Balancing Authorities when calculating
Reporting ACE.” We feel that by moving the requirement in this direction,
the associated VSLs can be set to adjustable criteria, such as the length
of time between detection and correction, i.e. under 15 minutes, under 30
minutes, etc.
The data retention of the proposed standard, current year plus three
years, is significantly larger than the one year retention found in the
current standard and goes beyond the three-year audit cycle for BAs. In
the context of a Risk-Based CMEP, we feel an entity should only need to
retain one year’s worth of data. There is minimal reliability benefit to
requiring an entity to store data for longer than one year, especially
considering the tools in place for the ERO to spot check or self-certify
compliance activities more frequently than an audit.
We believe the Implementation Plan should be updated to account for the
retirement of IRO-005-3.1a, as Requirement R1.6 of that standard has
the RC monitoring ACE and not Reportable ACE for all its BAs.
The third bullet of the proposed definition for Automatic Time Error
Correction, as listed within the Implementation Plan, has a typographical
error and should reference ε10.
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
Document Name:
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Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
As stated in the answer to Question 1, Texas RE is concerned the SDT has not
considered interconnections with a single BA. The initial SAR comments included
the following statement: “Within the Purpose statement or Applicability section,
the PRT also recommends that the SDT consider addressing the Hydro Quebec
exception for tie line bias control in some form, or a single-BA exception.“ It does
not appear the SDT addressed the single-BA issue which results in the Reliability
Standard not being applicable to the ERCOT and Quebec Interconnections. This,
in turn, affects BAL-001 applicability. If Reporting ACE is not applicable to
interconnections with a single BA, BAL-001 might not apply to the ERCOT and
Quebec Interconnections. Additionally, any BA that connects with the ERCOT
Interconnection BA will not be able to accurately determine Reporting ACE which
could cause failure of BAL-001 for those BAs (assuming they utilize net
interchange values in their Reporting ACE). This omission creates a reliability
gap. Texas RE recommends including Interconnections with a single BA.
There seems to be some inconsistency with regards to definitions. For example,
the definition of “Reporting ACE” in the Standard is different than the NERC
Glossary of Terms (Glossary) but there is no redline. The definition of “AGC” is
different from the Glossary and there is a redline. Is intent of the SDT to change
both terms in the Glossary? Frequency Bias Setting is not defined within this
Standard so it appears there is no change to that term. Asynchronous Ties
should be included in the derivation of ACE where applicable. Without it,
Reporting ACE will be off by the magnitude frequency applicable to the flows
across a DC tie (especially if a trip of the DC occurs or an error in scheduling).
Texas RE noticed the term “adjacent” is not capitalized in M1. Texas RE
recommends removing “its” when describing “Adjacent Balancing Authority” as
there could be more than one Adjacent Balancing Authority in M1.
To make R5 consistent with the Purpose statement, Texas RE recommends
changing “operator” to System Operator to be clear on which “operator” the
information shall be made available. This change should also take place in the
VSL for R5.
Per the comment in Question 1, R7 should be for all BAs not just BAs “within a
multiple Balancing Authority Interconnection”. R7 should only be relevant to the
area of the Balancing Authority that is implementing an Operating Process.
Texas RE noticed the VSL for R1 does not include language should include
language for each Tie Line, Pseudo-Tie or Dynamic Schedule to be equipped
with an agreed upon source to determine values. As is, the VSL ignores the
“equipped” language within the Standard.
Texas RE noticed the VSL language for R3 does not include “for 30 consecutive
minutes”. Should there be a dash in “30-consecutive” in Requirement 3?
Texas RE recommends changing the verbiage from “each calendar year” to
“annually” or for “each rolling 12 month period”. Specifically, R4 and R6 include
the term “calendar year” which implies Jan 1 to Dec 31. Therefore, if a CEA
evaluates compliance to the Requirement in mid-year, there cannot be an
assertion of compliance for the current year. Consequently, if the CEA returns in
two years, the half year’s period of data should be available to ascertain
compliance (per the Evidence Retention statements. Texas RE would like the
SDT consider whether this violates the RoP Appendix 4C Section 3.1.4.2 Period
Covered “The audit period will not begin prior to the End Date of the previous
Compliance Audit.”? Morever, does it cause a gap in compliance monitoring (and
reflect a possible gap in reliability)?
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Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
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0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
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John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
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John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
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0
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David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Answer Comment:
Ameren supports MISO's comments for this question
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Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
FMPA disagrees with the use of the term “accuracy” in R4.2. We believe the
intent would be better described by the term “precision”, or perhaps “degree of
accuracy”.
FMPA does not find any technical justification for the 99.5% availability
requirement in R6, and believes it may be duplicative with BAL-001 and present a
double jeopardy issue.
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Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
Document Name:
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Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
Proposed Standard:
Located in BAL-005-1 R1:
R1. Each Balancing Authority shall ensure that each Tie Line, Pseudo Tie, and
Dynamic Schedule with an Adjacent Balancing Authority is equipped with a
mutually agreed upon time synchronized common source to determine hourly
megawatt hour values.
1.1. These values shall be exchanged between Adjacent Balancing Authorities.
The phrase “Tie-Line” is not listed in the NERC Glossary, but instead “Tie Line” is
listed.
Definition:
o Tie Line:
• A circuit connecting two Balancing Authority Areas.
The definition of “Pseudo-Tie” should be updated to include Reporting ACE if that
is the purpose of the BAL-005-1 R1.
Definition:
o Pseudo-Tie:
• A time-varying energy transfer that is updated in Real-time and included
in the Actual Net Interchange term (NIA) in the same manner as a Tie Line in the
affected Balancing Authorities’ control ACE equations (or alternate control
processes).
If the SDT chooses not to change the language for R1, the language in R1.1
should be modified. With the current langauge the purpose of R1.1 is to exchange
the hourly megawatt hour values with the appropriate Balancing Authority to
determine billing and Inadvertent Interchange. This should be stated more clearly
as the current requirement has it written that the values are shared with [any]
Adjacent Balancing Authority.
PJM proposes the following R1.1:
1.1. These values shall be exchanged for each Tie Line, Pseudo Tie, and
Dynamic Schedule shared between affected Balancing Authorities.
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Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
x
Answer Comment:
x
x
x
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In the Mapping Document for BAL-005-1, R9, there appears to be a
contradiction in the Description and Change Justification section about
the HVDC links and their inclusion or not in Reporting ACE calculation vs
the definitions of Scheduled and Actual Net Interchanges that exclude
asynchronous DC tie-lines directly connected to another interconnection.
R1 vs R8: HQ faila to see the difference between the 2
requirements. Perhaps the Rationales should be enhanced for a better
understanding.
M1 and M8 do not seem appropriate measures for an agreement on
common metering or other sources. HQ suggesst favoring a written
agreement rather than operator logs or voice recordings.
Even though HQ agrees that balancing authorities should use common
metering equipment, we feel that R1 does not belong in BAL-005. This
requirement relates to energy measurements that are used for
accounting purposes and that do not come into play in reporting ACE
calculation. This requirement should remain in BAL-006 and does not
affect in any way automatic generation control. R8 does address
perfectly the common metering needs between balancing authorities for
real-time control.
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Answer Comment:
For BAL-005, R8, “MW Flow Values” should be specifically mentioned in R8 and
not just in the R8 Rationale.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
General comment: Duke Energy recommends the drafting team consider
moving the proposed R8 to R2. We feel that based on the common subject
matter of both of these requirements, that it would be more appropriate to
have them consecutively listed within a standard.
R4: Duke Energy requests further clarification regarding on how an entity
may demonstrate compliance with R4.2 specifically. Also, more background
information regarding where the 0.001Hz number came from and what it is
measure against would add to clarity of the standard. Perhaps an Operating
Guideline that provides guidance or examples on how an entity may
demonstrate compliance, as well as a background on the 0.001Hz number.
R5: We request further clarification on the use of the term operator in R5. Is
this in reference to a System Operator, if so, we recommend stating so in
the standard. As written, it appears that the standard is in conflict with the
rationale for R5 which uses the term System operator.
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Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
Answer Comment:
As worded, we do not believe that BAL-005-0.2b Requirement R1 is appropriate
for FAC-001-3. Since FAC-001-3 applies to documented Facility interconnection
requirements, it would be more appropriate to require that the documented
interconnection requirements contain language stating that transmission,
generation and end-user interconnected Facilities must be located within the
Balancing Authority Area’s metered boundaries. This could be accomplished by
adding R3.3 stating “Procedures for ensuring that transmission Facilities,
generation Facilities and end-user Facilities are within the Balancing Authority
Area’s metered boundaries.” The requirement to verify that existing facilities are
located with the metered boundaries of a Balancing Authority Area is most
appropriately assigned to the TOP, and not to the TO, GO and the LSE.
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Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
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0
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Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Answer Comment:
KCP&L incorporates by reference its response to Survey Question No. 2.
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Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Answer Comment:
Document Name:
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0
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0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
In the Automatic Generation Control (AGC) definition consider removing
“Automatically adjusts” and replace it with “determines”. The BA does not always
have the capability of making an automatic adjustment. For example, a BA can
send a requested loading value down through the RIG (Remote Intelligent
Gateway) and have the local GO/GOP or DP/LSE with smaller units to meet the
load, but do not have direct control over the units. It’s the local GO/GOP or
DP/LSE who owns and/or operates the units that actually execute changes in
loading.
Requirement R1
The use of the following text needs to be reconsidered:
… each Tie Line, Pseudo Tie, and Dynamic Schedule with an Adjacent BA…
… time-synchronized common source…
… to determine hourly megawatt hour values
Pseudo-ties and Dynamic Schedules are not tie lines; they are output values from
resources. In some cases these output values can be used directly, but in other
cases the values are adjusted by the EMS to represent the proportion of the
output to be incorporated into the BAs ACE.
The phrase “time-synchronized common source” requires explanation. If two BAs
are using a common source for real time flows, then by definition the values are
synchronized. If, on the other hand, R1 only applies to Hourly (Billing) values the
phrase is still superfluous. However, if the phrase is meant to mandate that all
inter-tie meters be synchronized to a common time, then that needs to be
explained more clearly.
Agree that Real-time metering of interties requires the use of common sources to
both BAs (as per Requirement 8). But given that R1 is focused on hourly
megawatt-hour values, the requirement becomes a market/billing issue not a
Real-time issue. R1 should be revised to clarify the intent.
Suggest that the Real-time installation of meters be left to BA Certification.
Requirement R2
What is meant by a 6 second sampling rate? Is that that the rate that a BA
samples the data values it has at the moment, or does the 6 seconds represent a
time delay between real-time and ACE calculations? This can be an issue for BAs
that make use of multi-tier samples, where Owner X samples a group of
resources every X-seconds, then sends that block of data to the BA who would
sample all the blocks every Y-seconds.
Traditionally, sampling rates were associated with how well a continuous function
can be recreated. A sampling rate that is slower that the fundamental oscillations
in the continuous function will not be able to reproduce that original function (the
issue of aliasing as experienced in watching a TV program in which a wheel
appears to rotate in the wrong direction).
What is the reliability justification for this scan rate?
Requirement R4
The value of monitoring system frequency is recognized, but again as suggested
in our response to R1, the issue of frequency monitoring would seem to be better
suited to a certification process rather than to a mandatory standard.
What is the justification for the values in Parts 4.1 and 4.2?
Requirement R5
The value of alarming is recognized, but given the fact that R5 could be a federal
law, the question could be asked:
x
x
What constitutes “quality” as in quality flags?
What constitutes “invalid” as in invalid data?
The concern addressed in R5 (alarming) would be better addressed in
certification. The systems that are certified should have alarming processes built
into them, customized to the needs of the BA.
Requirement R6
Real-time errors in the ACE components are reflected in various other
parameters:
1.
System Frequency
2.
Time Error (even if TE is not a standard is still computed)
3.
End of Day checkouts
4.
End of Month billing
As written R6 is an exercise is data collection and manipulation.
What are the implications of an unavailability less than 99.5%, and at what points
are reliability impacted (and how)?
Requirement R7
Requirement R7 requires clarification.
The process of monitoring for data errors and the process for mitigating errors
that are identified are built into modern EMS systems.
The requirement as written focuses only on errors “affecting the scan rate
accuracy of data used in the calculation of Reporting ACE…”. As written, this is
not all data used in ACE. Moreover, data does not impact the accuracy of the rate
of scanning. The rate of scanning is a built in function to the EMS / SCADA
programs. The data (good or bad) is scanned regularly.
As written R7 does not rise to the level of a NERC standard and should be
deleted.
The intent of R1 should be to ensure that a common metering point be identified
for all Real-time inter-BA tie lines. The issue of Pseudo-Ties and Dynamic
Schedules is really a business agreement between the two BAs in cooperation
with the resource being used, and therefore is not a standard matter.
Requirement R8
The requirement is on Pseudo-ties and Dynamic Schedules, but Pseudo-Ties and
Dynamic Schedules are not tie lines, they are output values from resources. In
some cases these output values can be used directly, but in other cases the
values are adjusted by the EMS to represent the proportion of the output to be
incorporated into the BA’s ACE.
The requirement to utilize a common source for all interties is a valid requirement.
The agreements referred to in R8 are Interconnection Agreements and therefore
not a matter for a NERC standard.
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Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
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Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Answer Comment:
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Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
Answer Comment:
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Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
See file attached to Question 1 for the SRC comments on the rationale and
language of several requirements.
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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
In general, BPA agrees with the current draft of BAL-005-1 but has some
concerns with how BAs will meet the proposed R7 – relating to implementing an
“Operating Process”. BPA believes that R7 is poorly written and needs to be
revisited.
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Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Answer Comment:
N/A
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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
Identification of common sources of measurement (R8) and recording (R1) are
BA certification items, not ongoing responsibilities that need to be checked
periodically. New tie lines or “inputs” into the BA ACE calculations should be
captured in FAC-001.
There is continued confusion regarding the six second scan rate. A BA can
demonstrate a scan rate of its received data every six seconds, but there is no
requirement for the data “made available to” the BA to be scanned at a certain
scan rate. To be more clear, the requirement should specify that “measurements
should be made by the common source(s) and provided to the BA at least every
six seconds for the calculation of Reporting ACE”. At its worst, that should result
in an ACE calculation being made and reported with data no longer than 12
seconds old.
The Rational for Requirement R3 leads with a sentence that has no basis in the
Functional Model and should be deleted. The RC does not have responsibility
“for coordinating the reliability of bulk electric systems for member BA’s.” The RC
is responsible for “Mitigating energy and transmission emergencies” among other
things. The statement made in the Rationale overstates the responsibility of the
RC and minimizes the BA role. The BA has primary responsibility for maintaining
load and generation balance and the RC has authority to step in and provide
assistance if the BA is unable to maintain its obligations. Delete the first sentence
of the Rationale for R3 box. What purpose does it serve to allow a BA an
additional 15 minutes after 30 minutes of an inability to calculate ACE before
notifying the RC. Delete “within 45 minutes of the beginning … ACE” and replace
with “without delay”. As stated, the requirement would allow a BA to not calculate
Reporting ACE for 44 minutes and then notify the RC. Or would require a BA that
could not calculate Reporting ACE for 31 minutes but then was successful to also
notify the RC. The intent of the change is not clear and seems to indicate a
reduction in reliability.
What is the specific rationale for requirement of 99.95% (or 0.05% outage
allowance = 43 seconds/day) uptime for frequency measurement? Is some
reliability threshold crossed at 44 seconds of frequency measurement
unavailability each day? Is the intent of R4.2 to still require calibration of the
measurement or simply to utilize a provided significant digit of .001 Hz? The new
R4 uses the term “accuracy” of .001Hz rather than the old R17 description of
“<=0.001Hz”. Also the measurement M4 requires demonstration of “minimum
accuracy” which lends itself to requiring a demonstrable calibration that is not
specifically stated in R4. The intended statement in the mapping document for
R17 to R4 is not captured well in the resulting R4.
Suggest deleting R5 and suggest this requirement be evaluated for inclusion in
the Project 2009-02 Real-Time Monitoring and Analysis Capabilities work since it
relates to identifying sources of inccorect input data. Any Operating Process or
Procedure to identify, correct, or mitigate incorrect or lost input data out of Project
2009-02 should include ACE data. If kept, the Measure M5 includes an additional
requirement that the suspect/garbage data indication should be indicated on
BOTH the calculated Reporting ACE result as well as on the individual
suspect/garbage data point. We suggest that R5 should include similar language
to M5 if that is the intent. The RSAW should be adjusted based on changes to
R5 or M5.
Suggest deleting R6 as it is duplicative and in conflict with BAL-001-2. The
reliability implication of “knowing” ACE is to be able to ensure balance is
maintained. That is accomplished in CPS and BAAL and does not need to be
duplicated here. The reporting % does not indicate a direct measurement of
reliability and is administrative only.
Suggest deleting R7 and suggest this requirement be evaluated for inclusion in
the Project 2009-02 Real-Time Monitoring and Analysis Capabilities work since it
relates to identifying sources of inccorect input data. Any Operating Process or
Procedure to identify, correct, or mitigate incorrect or lost input data out of Project
2009-02 should include ACE data.
Regarding R8: There is no demonstration of the reliability impact of using noncommon meters between BA’s for the purpose of Reporting ACE. In fact, in order
to support reliability, the requirement should specify that redundant sources be
made available to be used for Reporting ACE. Loss of the single, common
source would result in lost input to the ACE calculation. A best practice that most
BA’s use is to identify a primary, common source for measurements and a
secondary, common source for measurements and ensure each adjacent BA is
using the same common source at the same time. Common source
measurements do not ensure accuracy, they just ensure the same error is
introduced in both adjacent ACE calculations and therefore net each other out.
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Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
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5. Please provide any issues you have on the proposed change to the BAL-006-3 standard and a
proposed solution.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
none
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Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
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Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Answer Comment:
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0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
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Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
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Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
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Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
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Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Answer Comment:
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Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
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Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Answer Comment:
We do not see the need to retain any of the BAL-006 requirements in a
NERC Reliability Standard. Standard. Inadvertent Interchange is calculated
for reconciliation purpose and as such, does not have any reliability value
for real-time operations or post-mortem analysis. The facilities used for
recording hourly Inadvertent Interchange are more suited to be stipulated in
the BA’s Organization Certification Requirements; the procedure to
calculate, reconcile and resolve disputes over Intervertent Interchange can
be put into operating guide or even in the NAESB’s business practices.
Consistent with the risk-based principle, we suggest that unless there is
clear demonstration that failure to calculate and reconcile Inadvertent
Interchange can adversely affect operating reliability, this standard should
be retired with its requirements transferred to other NERC and/or NAESB
documents.
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Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
R1 is embedded in R2 and R3 and therefore unnecessary.
The sub-bullets of R3 should be bullets and not
Requirements. Additionally, the end-of-day check should be an agreement
of on and off peak totals, not hourly values. There are INT standards that
require confirmation of hourly schedules.
In the compliance section, RROs do not fill out monthly summary reports
and submit them to NERC.
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Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
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0
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0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
The sub-requirements of R3 should be bullets, not sub requirements.
The end of day check should be an agreement of on and off peak totals, not
hourly values. Confirmation of hourly schedules are already required in other
standards.
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Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
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Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
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0
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Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Answer Comment:
No comments.
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0
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Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
Document Name:
We appreciate the SDT’s efforts to remove Requirement R3 from this standard.
Likes:
0
Dislikes:
0
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
In the revised language for BAL-006-3 R4, Texas RE recommends replacing
the undefined term “Regional Reliability Organization Survey Contact” with
Reliability Coordinator. This may be outside the purview of the SDT but
consideration should be provided to clarify the responsibility while the Standard is
being considered.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Answer Comment:
Ameren supports MISO's comments for this question
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
Document Name:
n/a
Likes:
0
Dislikes:
0
Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Answer Comment:
As stated in question #2 above, as worded, we do not believe these requirements
are appropriate for FAC-001-3. Since FAC-001-3 applies to documented Facility
interconnection requirements, it would be more appropriate to require that the
documented interconnection requirements contain language stating that
transmission, generation and end-user interconnected Facilities must be located
within the Balancing Authority Area’s metered boundaries. This could be
accomplished by adding R3.3 stating “Procedures for ensuring that transmission
Facilities, generation Facilities and end-user Facilities are within the Balancing
Authority Area’s metered boundaries.” The requirement to verify that existing
facilities are located with the metered boundaries of a Balancing Authority Area is
most appropriately assigned to the TOP, and not to the TO, GO and the LSE.
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Answer Comment:
KCP&L incorporates by reference its response to Survey Question No. 2.
Document Name:
Likes:
0
Dislikes:
0
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
The SRC recommends that BAL-006 be retired.
See file attached to Question 1 for the full text of the comments to Question
5
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
None.
Document Name:
Likes:
0
Dislikes:
0
Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Answer Comment:
N/A
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
The purpose of BAL-006-2 (and resulting BAL-006-3) do not impact reliability. In
fact, this enforceable Standard only serves to provide administrative metrics that
are then used to facilitate either financial or in-kind reimbursements. In order to
make this standard truly results based in relation to system reliability,
requirements such as a BA shall not accumulate inadvertent interchange in
excess of XX,XXX MWh per month would need to be created. No BA or RC will
ever take reliability actions or issue Operating Instructions in relation to the
accumulated or forecast accumulated inadvertent interchange. Resolution of
inadvertent is an after-the fact reimbursement and not a reliability issue.
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
6. Please provide any issues you have on the proposed change to the FAC-001-3 standard and a
proposed solution.
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
none
Document Name:
Likes:
0
Dislikes:
0
Andrew Pusztai - American Transmission Company, LLC - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Selected Answer:
Answer Comment:
In the “Table of Compliance Elements”, the Violation Severity Levels, R5 and
R6 should correctly refer to Transmission Owner and Generator Owner,
respectively (instead of Transmission Operator and Generator Operator)
Document Name:
Likes:
0
Dislikes:
0
Thomas Foltz - AEP - 5 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Tammy Porter - Tammy Porter On Behalf of: Rod Kinard, Oncor Electric Delivery, 1
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Louis Slade - Dominion - Dominion Resources, Inc. - 6 Group Information
Group Name:
Dominion
Group Member Name Entity
Region
Segments
Randi Heise
NERC Compliance Policy
NPCC
5,6
Connie Lowe
NERC Compliance Policy
SERC
1,3,5,6
Louis Slade
NERC Compliance Policy
RFC
5,6
Chip Humphrey
Power Generation Compliance
SERC
5
Nancy Ashberry
Power Generation Compliance
RFC
5
Larry Nash
Electric Transmission Compliance SERC
1,3
Candace L Marshall
Electric Transmission Compliance SERC
1,3
Larry W Bateman
Transmission Compliance
SERC
1,3
Jeffrey N Bailey
Nuclear Compliance
SERC
5
Russell Deane
Nuclear Compliance
NPCC
5
Voter Information
Voter
Segment
Louis Slade
6
Entity
Region(s)
Dominion - Dominion Resources, Inc.
Selected Answer:
Answer Comment:
Document Name:
Dominion submitted comments - 2010-14_2_1_BARCUnofficial_Comment_Form-20150715.docx
Likes:
0
Dislikes:
0
Richard Vine - California ISO - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeremy Voll - Basin Electric Power Cooperative - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Jeri Freimuth - APS - Arizona Public Service Co. - 3 Selected Answer:
Answer Comment:
APS agrees with moving these requirements from BAL-005 to the new FAC-0013. APS also agrees with the proposed requirement language. APS does not
agree that the measurements of these newly placed requirements have been
correctly drafted.
A Transmission Operator, Generator Operator, or Load-Serving-Entity possessing
the Facility interconnection requirements of the Transmission Owner they are
attempting to interconnect with is not proof they are within a Balancing Authority
Area. Evidence they are within a Balancing Authority Area would be
demonstrated by possessing an executed Interconnection Agreement or similar
contract. The measures will need to be corrected to reflect that. The RSAW will
need to be corrected to line up with those changes.
Document Name:
Likes:
0
Dislikes:
0
Leonard Kula - Independent Electricity System Operator - 2 Selected Answer:
Answer Comment:
We concur with the proposed revisions to FAC-001-3.
Document Name:
Likes:
0
Dislikes:
0
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO
Group Information
Group Name:
MRO-NERC Standards Review Forum (NSRF)
Group Member Name Entity
Region
Segments
Joe Depoorter
Madison Gas & Electric
MRO
3,4,5,6
Amy Casucelli
Xcel Energy
MRO
1,3,5,6
Chuck Lawrence
American Transmission Company MRO
1
Chuck Wicklund
Otter Tail Power Company
1,3,5
Theresa Allard
Minnkota Power Cooperative, Inc MRO
1,3,5,6
Dave Rudolph
Basin Electric Power Cooperative MRO
1,3,5,6
Kayleigh Wilkerson
Lincoln Electric System
MRO
1,3,5,6
Jodi Jenson
Western Area Power
Administration
MRO
1,6
Larry Heckert
Alliant Energy
MRO
4
Mahmood Safi
Omaha Public Utility District
MRO
1,3,5,6
Shannon Weaver
Midwest ISO Inc.
MRO
2
Mike Brytowski
Great River Energy
MRO
1,3,5,6
Brad Perrett
Minnesota Power
MRO
1,5
Scott Nickels
Rochester Public Utilities
MRO
4
Terry Harbour
MidAmerican Energy Company
MRO
1,3,5,6
Tom Breene
Wisconsin Public Service
Corporation
MRO
3,4,5,6
Tony Eddleman
Nebraska Public Power District
MRO
1,3,5
MRO
Voter Information
Voter
Segment
Emily Rousseau
1,2,3,4,5,6
Entity
Region(s)
MRO
MRO
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Terry BIlke - Midcontinent ISO, Inc. - 2 Selected Answer:
Answer Comment:
Do not change FAC-001 as this confuses the intent of the original
requirement. There is virtually no way to prove that a particular component is
within a BA. The original requirement was intended to be sure Control Areas
balanced. This is done by operating to common ties and performing Inadvertent
Interchange checkouts.
Document Name:
Likes:
0
Dislikes:
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chris Mattson - Tacoma Public Utilities (Tacoma, WA) - 5 Selected Answer:
Answer Comment:
1)
FAC-001-3 R5 Severe VSL should state “The Transmission Owner……” to
match R5 which places responsibility for the requirement on the Transmission
Owner. Currently the VSL states the Transmission Operator will comply.
2)
FAC-001-3 R6 Severe VSL should state “The Generator Owner……” to
match R6 which places responsibility for the requirement on the Generator
Owner. Currently the VSL states the Generation Operator will comply.
Document Name:
Likes:
0
Dislikes:
0
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Group Information
Group Name:
Southern Company
Group Member Name Entity
Region
Segments
Robert Schaffeld
Southern Company Services, Inc SERC
1
John Ciza
Southern Company Generation
and Energy Marketing
SERC
6
R Scott Moore
Alabama Power Company
SERC
3
William Shultz
Southern Company Generation
SERC
5
Voter Information
Voter
Segment
Marsha Morgan
1,3,5,6
Entity
Region(s)
Southern Company - Southern Company
Services, Inc.
SERC
Selected Answer:
Answer Comment:
Should the SDT disagree that existing processes are adequate to accomplish the
desired outcome (as described in the comments to Question #2), then the
following is recommended:
1. Remove the inseration of 4.1.3 and R5-R7.
2. Modify R3.2 to read “Procedures for notifying the BA, TOP and RC of
new or materially modified existing interconnections.”
3. Modify R4.2 to read “Procedures for notifying the BA, TOP and RC of
new interconnections.”
Additionally, if possible, it is recommended that there be continued coordination
with the FAC-001 team that produced FAC-001-2 in 2014 before any changes to
FAC-001-2 are made.
Document Name:
Likes:
0
Dislikes:
0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5 - WECC
Selected Answer:
Answer Comment:
As stated in question #2 above, as worded, we do not believe these requirements
are appropriate for FAC-001-3. Since FAC-001-3 applies to documented Facility
interconnection requirements, it would be more appropriate to require that the
documented interconnection requirements contain language stating that
transmission, generation and end-user interconnected Facilities must be located
within the Balancing Authority Area’s metered boundaries. This could be
accomplished by adding R3.3 stating “Procedures for ensuring that transmission
Facilities, generation Facilities and end-user Facilities are within the Balancing
Authority Area’s metered boundaries.” The requirement to verify that existing
facilities are located with the metered boundaries of a Balancing Authority Area is
most appropriately assigned to the TOP, and not to the TO, GO and the LSE.
Document Name:
Likes:
0
Dislikes:
0
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Group Information
Group Name:
ACES Standards Collaborators
Group Member Name Entity
Region
Segments
Bob Solomon
Hoosier Energy Rural Electric
Cooperative, Inc.
RFC
1
Ginger Mercier
Prairie Power, Inc.
SERC
1,3
Bill Hutchison
Southern Illinois Power
Cooperative
SERC
1
Michael Brytowski
Great River Energy
MRO
1,3,5,6
Ellen Watkins
Sunflower Electric Power
Corporation
SPP
1
John Shaver
Arizona Electric Power
Cooperative, Inc.
WECC
4,5
John Shaver
Southwest Transmission
Cooperative, Inc.
WECC
1
Ryan Strom
Buckeye Power, Inc.
RFC
4
Scott Brame
North Carolina Electric
Membership Corporation
SERC
3,4,5
Bill Watson
Old Dominion Electric
Cooperative
SERC
3,4
Voter Information
Voter
Segment
Brian Van Gheem
6
Entity
Region(s)
ACES Power Marketing
NA - Not Applicable
Selected Answer:
Answer Comment:
We believe FAC-001-3 should not be modified based on the reasons previously
provided in question #2. We recommend the SDT retire the requirements moved
from BAL-005-0.2b based on the reasons cited. At a minimum, we recommend
the SDT provide technical justification on why these requirements are necessary.
Document Name:
Likes:
0
Dislikes:
0
Jonathan Appelbaum - United Illuminating Co. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Rachel Coyne - Texas Reliability Entity, Inc. - 10 Selected Answer:
Answer Comment:
In R5, R6, and R7 it seems duplicitous to include, “metered boundaries” in the
phrase “Balancing Authority Area’s metered boundaries” because the first
sentence of Balancing Authority Area definition is “The collection of generation,
transmission, and loads within the metered boundaries of the Balancing
Authority.”
Texas RE noticed the Evidence Retention section does not address LSEs.
Texas RE noticed the format of FAC-001-3 does not follow the new NERC
Results Based Standards
Template.
Texas RE noticed the VSL for R5 refers to the “Transmission Operator” but the
Requirement is applicable to the Transmission Owner. The VSL for R6 refers to
the “Generator Operator” but the Requirement is applicable to the Generation
Owner.
Document Name:
Likes:
0
Dislikes:
0
Bob Thomas - Illinois Municipal Electric Agency - 4 Selected Answer:
Answer Comment:
Please see comment under Qustion 2 above.
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
John Fontenot - Bryan Texas Utilities - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
David Jendras - Ameren - Ameren Services - 3 Selected Answer:
Answer Comment:
In our opinion there appears to be an inconsistency between the Standard
and the Table of Compliance. The Applicability section 4.1.1 identifies the
Transmission Owner as a Functional entity. Requirement R5 identifies the
Transmission Owner with responsibility for confirming facilities are located
within the BA boundaries. However, in the Table of Compliance Elements
for requirement R5, the Transmission Operator is identified with this
responsibility under the Severe VSL column. We believe that the
Transmission Operator should be changed to Transmission Owner to be
consistent with the requirements of the Standard.
Document Name:
Likes:
0
Dislikes:
0
Carol Chinn - Florida Municipal Power Agency - 4 Group Information
Group Name:
FMPA
Group Member Name Entity
Region
Segments
Tim Beyrle
City of New Smyrna Beach
FRCC
4
Jim Howard
Lakeland Electric
FRCC
3
Greg Woessner
Kissimmee Utility Authority
FRCC
3
Lynne Mila
City of Clewiston
FRCC
3
Javier Cisneros
Fort Pierce Utility Authority
FRCC
4
Randy Hahn
Ocala Utility Services
FRCC
3
Don Cuevas
Beaches Energy Services
FRCC
1
Stan Rzad
Keys Energy Services
FRCC
4
Matt Culverhouse
City of Bartow
FRCC
3
Tom Reedy
Florida Municipal Power Pool
FRCC
6
Steven Lancaster
Beaches Energy Services
FRCC
3
Mike Blough
Kissimmee Utility Authority
FRCC
5
Mark Brown
City of Winter Park
FRCC
3
Mace Hunter
Lakeland Electric
FRCC
3
Voter Information
Voter
Segment
Carol Chinn
4
Entity
Region(s)
Florida Municipal Power Agency
Selected Answer:
Answer Comment:
Document Name:
see question2
Likes:
0
Dislikes:
0
Scott McGough - Georgia System Operations Corporation - 3 Selected Answer:
Answer Comment:
1.
R7 seems to not even fit with the stated purpose of FAC-001-3 for
interconnecting (lowercase) to Facilities. What is the purpose of R7? Capitalized
term “Interconnection” simply means “When capitalized, any one of the three
major electric system networks in North America: Eastern, Western, and
ERCOT.” Reading the requirement at face value…if your load is anywhere in
Eastern, Western , or ERCOT Interconnection area then confirm its in a BA
Area’s metered boundaries. Is the intent of R7 to identify which BA area the load
is in? or is the intent to simply identify “yes” it is in “a BAs Area’s metered
boundary”? How does knowing or not knowing this have adverse impacts on the
reliability of the BES with respect to the purpose of the standard?
In addition, note that from NERC’s filing to FERC – Supplemental Information to
Petition for Approval of Proposed Transmission Operations and Interconnection
Reliability Operations and Coordination Reliability Standards, RM15-16, dated
May 12, 2015 – NERC states that “An LSE does not own or operate Bulk Electric
System facilities or equipment or the facilities or equipment used to serve enduse customers.21 (footnote 21 - The Distribution Provider is the functional entity
that provides facilities that interconnect an end-use customer load and the electric
system for the transfer of electrical energy to the end-use customer. If a company
registered as an LSE also owned facilities, the company would be registered for
other functions as well.
2.
Measure M7 implies that LSEs have Facility interconnection requirements
when there are no such requirements, thus complicating complying with
R7. Does the drafting team intend for the LSE to provide a copy of the Facility
interconnection requirements documents they may have received from the TO
when requesting to interconnect to the transmission owner?
3.
Depending on understanding the true intent of this requirement, we would
be in favor for an attestation to be included in the measure, but then … seems
like a pointless, administrative requirement that meets P81.
Document Name:
Likes:
0
Dislikes:
0
Mark Holman - PJM Interconnection, L.L.C. - 2 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Theresa Rakowsky - Puget Sound Energy, Inc. - 1 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
Group Information
Group Name:
Duke Energy
Group Member Name Entity
Region
Segments
Doug Hils
Duke Energy
RFC
1
Lee Schuster
Duke Energy
FRCC
3
Dale Goodwine
Duke Energy
SERC
5
Greg Cecil
Duke Energy
RFC
6
Voter Information
Voter
Segment
Colby Bellville
1,3,5,6
Entity
Region(s)
Duke Energy
FRCC,SERC,RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Andrea Basinski - Puget Sound Energy, Inc. - 3 Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Group Information
Group Name:
LG&E and KU Energy, LLC
Group Member Name Entity
Region
Segments
Brent Ingebrigtson
LG&E adn KU energy, LLC
SERC
1,3,5,6
justin Bencomo
LG&E and KU Energy, LLC
SERC
1,3,5,6
Chjarlie Freibert
LG&E and KU Energy, LLC
SERC
3
Linn Oelker
LG&E and KU Energy, LLC
SERC
6
Dan Wilson
LG&E and KU Energy, LLC
SERC
5
Voter Information
Voter
Segment
Brent Ingebrigtson
1,3,5,6
Entity
Region(s)
LG&E and KU Energy, LLC
SERC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Douglas Webb - Douglas Webb On Behalf of: Chris Bridges, Great Plains Energy - Kansas City
Power and Light Co., 3, 6, 5, 1
Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
James McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 6, 5, 1
Selected Answer:
Answer Comment:
KCP&L incorporates by reference its response to Survey Question No. 2.
Document Name:
Likes:
0
Dislikes:
0
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
Selected Answer:
Answer Comment:
Document Name:
Likes:
0
Dislikes:
0
Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC
Group Information
Group Name:
NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls BAL-005-1, BAL-006-3, FAC-001-3
Group Member Name Entity
Region
Segments
Alan Adamson
New York State Reliability
Council, LLC
NPCC
10
David Burke
Orange and Rockland Utilities
Inc.
NPCC
3
Greg Campoli
New York Independent System
Operator
NPCC
2
Gerry Dunbar
Northeast Power Coordinating
Council
NPCC
10
Mark Kenny
Northeast Utilities
NPCC
1
Helen Lainis
Independent Electricity System
Operator
NPCC
2
Rob Vance
New Brunswick Power
Corporation
NPCC
9
Paul Malozewski
Hydro One Networks Inc.
NPCC
1
Bruce Metruck
New York Power Authority
NPCC
6
Lee Pedowicz
Northeast Power Coordinating
Council
NPCC
10
David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
Brian Robinson
Utility Services
NPCC
8
Wayne Sipperly
New York Power Authority
NPCC
5
Edward Bedder
Orange and Rockland Utilities
Inc.
NPCC
1
Michael Jones
National Grid
NPCC
1
Brian Shanahan
National Grid
NPCC
1
Glen Smith
Entergy Services, Inc.
NPCC
5
RuiDa Shu
Northeast Power Coordinating
Council
NPCC
10
Connie Lowe
Dominion Resources Services,
Inc.
NPCC
5
Guy Zito
Northeast Power Coordinating
Council
NPCC
10
Silvia Parada Mitchell
NextEra Energy, LLC
NPCC
5
Robert Pellegrini
The United Illuminating Company NPCC
1
Kathleen Goodman
ISO - New England
2
NPCC
Voter Information
Voter
Segment
Lee Pedowicz
10
Entity
Region(s)
Northeast Power Coordinating Council
NPCC
Selected Answer:
Answer Comment:
Given that NERC is in the process of delisting the LSE from the Functional Model
and the NERC registry, suggest revising Requirement R7 to read “Each
Distribution Provider that provides facilities that interconnect a customer Load
shall confirm that each customer Load is within a Balancing Authority Area’s
metered boundaries.” Measure M7 would need to be revised accordingly.
This standard is unnecessary given the fact that Interconnection Agreements are
contractual legal documents that address and spell out the details addressed by
the various FAC-001 requirements.
Also, the use of the requirement “shall address” is not a clear mandate and is
open to interpretation by both the Responsible Entity and the Regional
Enforcement entity.
The wording in Measures M5 thru M7 appear to have been copied from Measures
M3 and M4, mentioning “dated, documented Facility interconnection requirements
addressing the procedures” as evidence that the requirements are met. The
wording in these Measures is appropriate for M3 and M4, but not M5 thru M7.
Document Name:
Likes:
0
Dislikes:
0
Jason Snodgrass - Georgia Transmission Corporation - 1 Selected Answer:
Answer Comment:
In addition to the comments GTC listed in Question 2, GTC believes the response
to R5 as a TO would simply be "yes" and is unaware how this answer enhances
reliable operation of the BES. Therefore, GTC does not quite understand the
intent of these requirements as they are written. Confirm which BA Area the
Transmission Facility is located in? Confirm to whom? GTC see's this as
administrative in nature subject to P81 criteria.
Document Name:
Likes:
0
Dislikes:
0
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 Selected Answer:
Answer Comment:
We appreciate the work by the SDT, but do not agree with moving BAL-005-0.2b
Requirement R1 to FAC-001-3 Requirements R5, R6, and R7. At this time, the
way the BAL-005 requirement R1 reads it poses to be more of an accounting
issue versus a reliability issue. One alternative solution is to remove the language
from this standard (FAC-001-3) and include it in the Application Guidelines
section.
Document Name:
Likes:
0
Dislikes:
0
Payam Farahbakhsh - Hydro One Networks, Inc. - 1 Selected Answer:
Answer Comment:
Hydro One supports all comments provided by NPCC RSC regarding the draft of
FAC-001-3.
Document Name:
Likes:
0
Dislikes:
0
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC
Group Information
Group Name:
ISO Standards Review Committee
Group Member Name Entity
Region
Segments
Charles Yeung
SPP
SPP
2
Ben Li
IESO
NPCC
2
Mark Holman
PJM
RFC
2
Kathleen Goodman
ISONE
NPCC
2
Greg Campoli
NYISO
NPCC
2
Ali Miremadi
CAISO
WECC
2
Terry Bilke
MISO
RFC
2
Christina Bigelow
ERCOT
TRE
2
Voter Information
Voter
Segment
Albert DiCaprio
2
Entity
Region(s)
PJM Interconnection, L.L.C.
RFC
Selected Answer:
Answer Comment:
The SRC recommends that FAC-001-2 be retired
See file attached to Question 1 for the full text of the comments to Question
6
Document Name:
Likes:
0
Dislikes:
0
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Selected Answer:
Answer Comment:
None.
Document Name:
Likes:
0
Dislikes:
0
Shawna Speer - Colorado Springs Utilities - 1 Group Information
Group Name:
Colorado Springs Utilities
Group Member Name Entity
Region
Segments
Shawna Speer
Colorado Springs Utilities
WECC
1
Shannon Fair
Colorado Springs Utilities
WECC
6
Charles Morgan
Colorado Springs Utilities
WECC
3
Kaleb Brimhall
Colorado Springs Utilities
WECC
5
Voter Information
Voter
Segment
Shawna Speer
1
Entity
Region(s)
Colorado Springs Utilities
Selected Answer:
Answer Comment:
Again to illustrate the comments in response #2, FAC-001 is a facility
interconnection requirement standard so any changes here will be applied to
FAC-001 applicable functional entities documented facility interconnection
requirements. FAC-001 typically deals with new interconnections, so if the
intent of the FAC-001-3 R5-R7 is to make sure all transmission, generation, and
load are within a BAA metered bounds this is not the correct standard. R7 in its
entirety needs to be moved to another standard since it is not clear which
interconnection requirement it will fall under (i.e. TO and/or Applicable GO).
The FAC-001 standard can be used to require documented facility
interconnection requirements to address BAA metered bounds for all entities
seeking to interconnect. However to enforce this for BAA metered bounds for
those facilities that already exist within FAC-001, the documented facility
interconnection requirements would have to retroactively apply for those facilities
that already exist. R5-R6 needs to be moved to another standard.
Document Name:
Likes:
0
Dislikes:
0
Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - SPP
Group Information
Group Name:
SPP Standards Review Group
Group Member Name Entity
Region
Segments
Shannon Mickens
Southwest Power Pool
SPP
2
Jason Smith
Southwest Power Pool
SPP
2
Ashley Stringer
Oklahoma Municipal Power
Authority
SPP
4
Voter Information
Voter
Segment
Jason Smith
2
Entity
Region(s)
Southwest Power Pool, Inc. (RTO)
SPP
Selected Answer:
Answer Comment:
The first 4 requirements, which make up the existing FAC-001-2, are
administrative and should be moved to certification review. The new R5-7 are
necessary due to the removal from BAL-005. However as suggested earlier,
those requiremetns should also be included in the TO’s Facility Interconnection
Requirement documents and do not necessarily need to be specific Reliability
Standard Requirements. If R1-4 are kept, we recommend changing the phrase
“shall address” in R1-4 to “shall include”.
Document Name:
Likes:
0
Dislikes:
0
Erika Doot - U.S. Bureau of Reclamation - 5 Selected Answer:
Answer Comment:
Reclamation agrees with the periodic review team that it is important to verify
facilities are within the metered boundaries of a Balancing Authority Area before
they are operational, but believes that the requirement should be imposed
through interconnection or service agreements rather than a reliability
standard. As an alternative, FAC-001-3 R5 through R7 and M5 through M7 could
be rephrased to require a one-time confirmation prior to a facility being placed in
service.
Document Name:
Likes:
0
Dislikes:
0
Unofficial Comment Form
Project 2010-14.2.1 Phase 2 of Balancing Authority Reliabilitybased Controls
Do not use this form for submitting comments. Use the electronic form to submit comments on the
proposed revisions to BAL-005-1 – Balancing Authority Control, BAL-006-3 – Inadvertent Interchange,
FAC-001-3 – Facility Interconnection Requirements. The electronic form must be submitted by 8 p.m.
Eastern, Monday, September 14, 2015m. E
astern, Thursday, August 20, 2015.
Documents and information about this project are available on the project page. If you have questions,
contact Senior Standards Developer, Darrel Richardson (via email) or at (609) 613-1848.
Background Information
This posting is soliciting formal comments on the draft standards BAL-005-1 Balancing Authority Control,
BAL-006-3 Inadvertent Interchange and FAC-001-3 Facility Interconnection Requirements.
On September 19, 2013, the NERC Standards Committee appointed ten subject matter experts to serve on
the BARC 2 periodic review team (BARC 2 PRT). 1 As part of its review, the BARC 2 PRT used background
information on the standards and the questions set forth in the Periodic Review Template developed by
NERC and approved by the Standards Committee, along with associated worksheets and reference
documents, to determine whether BAL-005-0.2b and BAL-006-2 should be: (1) affirmed as is (i.e., no
changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3)
withdrawn. The recommendations of the BARC 2 PRT are in the Periodic Review Templates and SAR.
The Standards Committee approved a revised SAR to be posted for a 30-day comment period on June 10,
2014. The SAR was posted for comment from July 16, 2014 through August 14, 2014. The BARC Phase 2.1
standard drafting team (BARC 2.1 SDT) reviewed the comments received from the SAR posting and has
developed revisions to BAL-005-0.2b, BAL-006-2 and FAC-001-2 standards. The BARC 2.1 SDT has
completely re-written the BAL-005 standard, moved one requirement from the current BAL-005 standard
into the proposed FAC-001-3 standard and moved one requirement from the current BAL-006 standard
into the proposed BAL-005-1 standard. The balance of the requirements in the BAL-006-3 standard will
be reviewed for revision and posted at a later date.
This project addresses directives from FERC Order 693, and provides additional clarity to many
requirements, as well as retiring requirements that meet the criteria developed in the Paragraph 81
project.
This posting is soliciting comment on three standards; 1) BAL-005-1 Balancing Authority Control; 2) BAL006-3 Inadvertent Interchange; and 3) FAC-001-3 Facility Interconnection Re1quirements.
1
The Standards Committee subsequently appointed an eleventh SME to the BARC 2 PRT.
Questions
1. The SDT has modified the definition of Automatic Generation Control (AGC). Do you agree that
this modified definition better represents the SDT intent to making resources more inclusive than
just the traditional generation resources? If not, please explain in the comment area below.
Yes
No
Comments:
NOTE - Dominion has no entity registered as BA and will not submit any comment on this
question.
2. The SDT has moved the BAL-005-0.2b Requirement R1 to FAC-001 since it provides for identifying
interconnection Facilities and not for calculating Reporting ACE. Do you agree with moving this
requirement into the FAC-001-3 standard? If not, please explain in the comment area below.
Yes
No
Comments:
3. The SDT has moved the BAL-006-2 Requirement R3 into BAL-005-3 since this requirement directly
impacts an entity’s ability to calculate an accurate Reporting ACE. Do you agree with moving this
requirement into the proposed BAL-005-1 standard? If not, please explain in the comment area
below.
Yes
No
Comments:
NOTE - Dominion has no entity registered as BA and will not submit any comment on this
question.
4. Please provide any issues you have on this draft of the BAL-005-1 standard and a proposed
solution.
Comments:
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
2
5. Please provide any issues you have on the proposed change to the BAL-006-3 standard and a
proposed solution.
Comments:
6. Please provide any issues you have on the proposed change to the FAC-001-3 standard and a
proposed solution.
Comments:
Given that NERC is in the process of delisting the LSE from the Functional Model and the NERC
registry, Dominion suggests revising Requirement 7 to read “Each Load-Serving Entity Distribution
Provider with Load operating in an Interconnection that provides facilities that interconnect an eEnd-use
cCustomer load shall confirm that each eEnd-use cCustomer Load is within a Balancing Authority Area’s
metered boundaries. If this suggestion is accepted by the SDT, corresponding changes would need to be
made to Measure 7.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
3
1. The SDT has moved the BAL-005-0.2b Requirement R1 to FAC-001 since it provides for
identifying interconnection Facilities and not for calculating Reporting ACE. Do you
agree with moving this requirement into the FAC-001-3 standard? If not, please
explain in the comment area below.
Yes
No
Comments: It is not necessary to move this requirement. The SDT is taking a flawed
requirement and moving it to another location. The requirement should be improved as
follows.
R1. All generation, transmission, and load operating within an Interconnection
must be included within the metered boundaries of a Balancing Authority
Area.
R1.1. Each Generator Operator with generation facilities operating in an
Interconnection shall ensure that those generation facilities are
included within the metered boundaries of a Balancing Authority
Area.
R1.2. Each Transmission Operator with transmission facilities operating in
an Interconnection shall ensure that those transmission facilities are
included within the metered boundaries of a Balancing Authority
Area.
R1.3. Each Load-Serving Entity with load operating in an Interconnection
shall ensure that those loads are included within the metered
boundaries of a Balancing Authority Area.
The requirement above was a concept (Control Area Criteria) that was swept
into the V0 standard. The only way to prove that everything is within the
metered bounds of a BA is via Inadvertent Interchange accounting. R1 should be
kept as-is, the sub-bullets removed and the measure for R1 should be:
M1. The Balancing Authority was unable to agree with an Adjacent Balancing
Authority when performing Inadvertent Interchange accounting and it was
found that the Balancing Authority had an error in its model or tie lines that
misstated its Net Actual Interchange value in its Inadvertent Interchange
accounting.
4. Please provide any issues you have on this draft of the BAL-005-1 standard and a
proposed solution.
Comments:
The proposed R1 should be shortened and merged with R7. There need not be mention
of “mutually agreed upon” nor “time synchronized”. AGC and ACE use real-time values,
not hourly values.
BAL-005-1
R1. Each Balancing Authority shall ensure that have a process to operate to
common, accurate each Tie-Lines, Pseudo-Ties, and Dynamic Schedules
with its an Adjacent Balancing Authorities. is equipped with a mutually
agreed upon time synchronized common source to determine hourly
megawatt-hour values
The measure of this requirement is not logs or voice recordings. NSI is already
checked with Inadvertent Accounting and the INT standards. The process
that was proposed in R7 could be the validation and measure for R1
If the change to R1 above is made, R7 is no longer necessary.
R8 is redundant with when compared to the suggested wording above for BAL005-1 R1 and BAL-006 R3.
Unofficial Comment Form
Project 2010-14.2.1 Phase 2 of Balancing Authority Reliabilitybased Controls
Do not use this form for submitting comments. Use the electronic form to submit comments on the
proposed revisions to BAL-005-1 – Balancing Authority Control, BAL-006-3 – Inadvertent Interchange,
FAC-001-3 – Facility Interconnection Requirements. The electronic form must be submitted by 8 p.m.
Eastern, Monday, September 14, 2015m. E
astern, Thursday, August 20, 2015.
Documents and information about this project are available on the project page. If you have questions,
contact Senior Standards Developer, Darrel Richardson (via email) or at (609) 613-1848.
Background Information
This posting is soliciting formal comments on the draft standards BAL-005-1 Balancing Authority Control,
BAL-006-3 Inadvertent Interchange and FAC-001-3 Facility Interconnection Requirements.
On September 19, 2013, the NERC Standards Committee appointed ten subject matter experts to serve on
the BARC 2 periodic review team (BARC 2 PRT). 1 As part of its review, the BARC 2 PRT used background
information on the standards and the questions set forth in the Periodic Review Template developed by
NERC and approved by the Standards Committee, along with associated worksheets and reference
documents, to determine whether BAL-005-0.2b and BAL-006-2 should be: (1) affirmed as is (i.e., no
changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3)
withdrawn. The recommendations of the BARC 2 PRT are in the Periodic Review Templates and SAR.
The Standards Committee approved a revised SAR to be posted for a 30-day comment period on June 10,
2014. The SAR was posted for comment from July 16, 2014 through August 14, 2014. The BARC Phase 2.1
standard drafting team (BARC 2.1 SDT) reviewed the comments received from the SAR posting and has
developed revisions to BAL-005-0.2b, BAL-006-2 and FAC-001-2 standards. The BARC 2.1 SDT has
completely re-written the BAL-005 standard, moved one requirement from the current BAL-005 standard
into the proposed FAC-001-3 standard and moved one requirement from the current BAL-006 standard
into the proposed BAL-005-1 standard. The balance of the requirements in the BAL-006-3 standard will
be reviewed for revision and posted at a later date.
This project addresses directives from FERC Order 693, and provides additional clarity to many
requirements, as well as retiring requirements that meet the criteria developed in the Paragraph 81
project.
This posting is soliciting comment on three standards; 1) BAL-005-1 Balancing Authority Control; 2) BAL006-3 Inadvertent Interchange; and 3) FAC-001-3 Facility Interconnection Re1quirements.
1
The Standards Committee subsequently appointed an eleventh SME to the BARC 2 PRT.
Questions
1. The SDT has modified the definition of Automatic Generation Control (AGC). Do you agree that
this modified definition better represents the SDT intent to making resources more inclusive than
just the traditional generation resources? If not, please explain in the comment area below.
Yes
No
Comments:
The SRC does not agree with the proposed definition of AGC.
The SRC recommends the following definition for AGC:
Automatic Generation Control (AGC): A process designed and used to adjust a
Balancing Authority’s resources to meet the BA’s balancing requirements as required by
applicable NERC Reliability Standards.
Rationale:
1. The BAL-005 definitions should not include any references to Automatic Time Error Correction
(I ATEC).
BAL-005 is a NERC standard applicable to all Interconnections - not one of the many
regionally-approved standards. This standard is approved for all BAs unless the BA is in a
region in which the standard is superseded by a FERC-approved regional standard. As such,
the SRC believes the definition and references to Automatic Time Error Correction (I ATEC )
should be deleted and left to the regionally-approved regional standard.
2. The following phrases / terms used in the proposed definition of AGC are ambiguous or not
precise.
x
Centrally located equipment
This phrase should be deleted.
There is no justification to link the definition of Automatic Generation Control (AGC)
to a given location given that AGC is a process (software) not equipment
(hardware).
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
2
x
…that automatically adjusts…
This phrase should be reworded.
There is no direct link between an AGC signal and the response of a resource. As
written the failure of a resource to respond to an AGC signal would constitute a
violation on the part of the BA.
It would be more correct to state that AGC “is used to adjust resources”.
x
…maintain Reporting ACE…
This phrase should be deleted.
AGC is not designed for reporting purposes. AGC is designed to assist in the control
of a BA’s balancing of its resources to its NERC mandated balancing obligations.
x
Resources utilized under AGC…
This sentence should be deleted.
x
x
AGC does not “utilize” resources, but – rather – evaluates resource utilization
within a balancing Authority Area to ensure that load and resources remain in
balance. More specifically, resources are an input to AGC.
The sentence itself is a partial list of supply resources and therefore not critical
to defining the term itself.
2. The SDT has moved the BAL-005-0.2b Requirement R1 to FAC-001 since it provides for identifying
interconnection Facilities and not for calculating Reporting ACE. Do you agree with moving this
requirement into the FAC-001-3 standard? If not, please explain in the comment area below.
Yes
No
Comments:
The SRC supports deleting the R1 requirements in BAL-005-0.2b, and recommends placing
the obligation in a certification requirement.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
3
Rationale: (also see response to Question 6 below)
1. BAL-005-0.2b R1 addresses AGC. R1.1 – R1.3 address administrative items that are generally
contained within Interconnection Agreements as legal terms and conditions – not as reliabilityrelated concerns or issues
2. If R1 and its sub-requirements were reliability standards, they would result in an unnecessary
annual exchange of paperwork between and among asset owners, BAs and the ERO.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
4
3. The SDT has moved the BAL-006-2 Requirement R3 into BAL-005-3 since this requirement directly
impacts an entity’s ability to calculate an accurate Reporting ACE. Do you agree with moving this
requirement into the proposed BAL-005-1 standard? If not, please explain in the comment area
below.
Yes
No
Comments:
The SRC opposes the proposal to move BAL-006-2 Requirement R3 into BAL-005-3.
The SRC recommends that BAL-006 be deleted.
Rationale:
The SRC opposes this proposal for the following reasons:
1. The two standards address issues that are in two different time horizons (BAL-005 is a real
time horizon (MW), while BAL-006 is an hourly horizon (MWhr). To combine the two
standards into a single standard will confuse the objectives of each of these time horizons
and the associated functions.
2. The collection of hourly (Inadvertent Interchange) data proposed by the transferred
requirement (R3) does not affect the real time calculation of Reporting ACE. BAL-006 is a
standard for Inadvertent Interchange which is an after-the-fact accounting function as
opposed to BAL-005 which is about real-time reliability function.
3. Real time metering of interconnecting points is better handled as a certification issue given
that such metering is relatively static and stable and does not require continuous the
continuous review mandated by a reliability standard.
4. The objective of R3 is not clear as currently proposed. Specifically, it is unclear if R3 is
meant:
x As a procedural mandate that BAs use a single real-time point of metering for
interconnection points used in the ACE calculation?
x As a data reporting mandate on meters, that all interconnection point meters have the
ability to compute hourly readings? or
x As a data reporting mandate on BAs to communicate information on interconnection
points once an hour to adjacent BAs (in which case there is a need for a time criteria –
e.g. send the information within 4 hours of the clock hour).
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
5
Additionally, if Requirement R1 is meant as a data reporting requirement, it should have been
considered for retirement under the Paragraph 81 concept. If not, additional clarification is
needed, e.g., is it a certification requirement that mandates hardware.
The SRC also notes that NERC’s Independent Expert Review Panel recommended BAL-006 for
retirement because “This is only for energy accounting. Covered by Tagging requirements.”
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
6
4. Please provide any issues you have on this draft of the BAL-005-1 standard and a proposed
solution.
Comments:
The SRC provides comments on the rationale and language of several requirements below by
requirement.
Requirement R1
The SRC recommends:
x The rationale for R1 be reconsidered and corrected.
x The references in R1 to “time-synchronized common source” and “hourly megawatt-hour
values “ be deleted.
Rationale
The SRC questions the following text in the proposed “Rationale for Requirement R1”:
x The intent of R1 is to provide accuracy…
x R1 …used in… Reporting ACE, hourly inadvertent energy, and Frequency Response
measurements
x It [R1] specifies need for …instantaneous and hourly integrated …tie line flow values
x Common data source requirements also apply …
The intent of R1 is not accuracy (common source metering does not address accuracy). The intent
of R1 is to ensure a zero-sum data ensemble for all ACEs.
Contract-based billing meters used for Inadvertent Interchange are not necessarily the same as the
real time common source meters used in ACE. The text of R1 is not precise in what is the specific
objective for R1. The rationale states R1 is for instantaneous and hourly tie flow values but the
text of R1 states it is “…to determine hourly megawatt-hour values.”
The final sentence in the Rationale section regarding of other R1 applications is superfluous and
should be deleted.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
7
The SRC questions the following text:
x … time-synchronized common source…
x … to determine hourly megawatt-hour values
The phrase “time-synchronized common source” requires explanation.
If two BAs are using a common (MW) source for real time flows, then by definition the values are
synchronized. If, on the other hand, R1 only applies to Hourly (Billing) values (MWh) the phrase is
still superfluous. However, if the phrase is meant to mandate that all inter-tie meters be
synchronized to a common time, then that needs to be explained more clearly.
The SRC agrees that real time (MW) metering of inter-ties requires the use of common sources to
both BAs (as per Requirement 8). But given that R1 is focused on hourly megawatt-hour values,
the requirement becomes a market/billing issue not a real time issue. In short, the SDT is asked to
rewrite R1 in a fashion that clarifies the intent.
Requirement R2
The SRC recommends:
x The rationale for R2 be reconsidered and revised.
Rationale
The proposed “Rationale for Requirement R2” overstates its justification. Specifically the rationale
states that without frequency “…the BA operator will lack situational awareness and will be unable
to make correct decisions when maintaining reliability.”
The SRC does not agree that a BA would be “unable” to make correct decisions. The SRC
acknowledges that decision-making regarding impacts on and the support for frequency may be
more difficult. However, this difficulty does not threaten the reliability of the interconnection as
tie line flows will still be monitored by TOPs and system frequency will be monitored by other BAs,
TOPs and RCs.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
8
Requirement R4
The SRC recommends that sub-requirements (4.1 and 4.2) be deleted.
Rationale:
The SRC recognizes the value of monitoring system frequency, but suggests that the monitoring of
the availability and accuracy of frequency-monitoring equipment is a data collection and reporting
exercise that is onerous and administrative in nature. Such requirements would be better suited to
be addressed as part of a certification process or in guidance documents than as a mandatory
reliability standard.
In lieu of deleting the sub-requirements, the SRC requests the justification for the values in R4.1
and 4.2, and for the benefits to reliability that is to be obtained through the proposed
requirements.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
9
Requirement R5
The SRC recommends:
x R5 be addressed as part of a certification process.
x The rationale for R5 be reconsidered and revised.
Rationale
The SRC believes R5 (alarming) would be better addressed in certification than as part of a
reliability standard that is subject to continuous review as a reliability standard requirement. The
systems that are certified should have alarming processes built into them that are customized to
the needs of the respective BA. Such systems, once reviewed, are relatively static and not subject
to frequent modification. Additionally, although the SRC recognizes the values of alarming, it is
concerned that, in the context of a mandatory reliability standard, subjectivity will be introduced
regarding what constitutes “quality” for quality flags, and “invalid” for invalid data. Without an
objective measure for the aforementioned terms, Requirement R5 loses any value as a reliability
standard.
The proposed “Rationale for Requirement R5” states “When an operator questions the validity of
data, actions are delayed and the probability of adverse events occurring can increase.” While the
above could be true, there is no objective evidence to support the statement and therefore the
statement should be deleted.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
10
Requirement R6
The SRC recommends requirement R6 be deleted.
Rationale
The SRC recognizes the value of monitoring ACE calculation, but suggests the monitoring of the
availability of the software, etc. utilized to calculate ACE is a data collection and reporting exercise
that is onerous and administrative in nature. Such requirements are better addressed during the
certification process and in guidance documentation than as part of a mandatory reliability
standard.
The SRC is concerned that certain terms such as “available system” create ambiguity, e.g., what
would constitute an “available system.” Neither the requirement nor the measurement makes
clear what an available system is nor when a system would be deemed unavailable, e.g., is a
system “unavailable” to compute ACE if a single data sample is unavailable? Or when the entire
system is unavailable.
Requirement R7
The SRC recommends:
x R7 be deleted.
x The rationale for R7 be reconsidered and revised.
Rationale
The SRC suggests that as written, R7 is an administrative requirement that does not rise to the
level of a NERC standard and should be deleted.
Should Requirement R7 be retained, the SRC comments that the objective and obligation of a BA
under requirement R7 is ambiguous and requires additional explanation/clarification.
Additionally, the process of monitoring for and mitigating data errors that are identified are built
into modern EMS systems. Thus, the SDT proposed requirement for an “Operating Process,” which
is not a defined term in Glossary and should not be considered a proper noun in this requirement,
would be redundant of existing processes and functionality. Further, the requirement focuses only
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
11
on errors “affecting the scan-rate accuracy of data used in the calculation of Reporting ACE…” The
SRC asserts that data (in and of itself) generally does not impact the accuracy of the rate of
scanning, which is a built in function to the EMS / SCADA programs. The data (good or bad) is
scanned regularly.
The Rationale for R7 states that “…Without a process to address persistent errors in the ACE
calculation, the operator can lose trust in the validity of Reporting ACE resulting in delayed or
incorrect decisions regarding the reliability of the bulk electric system.”
The SRC requests that either justification and support for this statement be provided, or the
statement be deleted from the rationale section.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
12
Requirement R8
The SRC recommends:
x R8 be reviewed and revised.
x The Rationale for R8 be reconsidered and revised.
Rationale
The SRC believes that the issue of common source metering for all inter-ties, and of agreements
on allocating resources as pseudo-ties or dynamic schedules is best handled as Interconnection
Agreements or certification rather than as a reliability standard.
The SRC notes that Requirement 8 includes Pseudo-ties and Dynamic Schedules but Pseudo-ties
and Dynamic Schedules are not tie lines, but are output values from resources. In some cases
these output values can be used directly, but in other cases the values are adjusted by the EMS to
represent the proportion of the output to be incorporated into the BAs ACE, and thus do not
derive from common source meters.
The Rationale for R8 states that “…When data sources are not common, confusion can be created
between BAs resulting in delayed or incorrect operator action.” The SRC objects to this statement.
If data sources are not common, then the ACE values in an Interconnection no longer form a zerosum system. Such an error can only be identified in a tie-line by tie-line check. The result can be
all BAs meet the Control Performance requirements, but the Interconnection itself is experiencing
an imbalance that results in off-schedule frequency and time error. The SRC would point out that
any inaccuracies or errors in the ACE components are reflected in various other parameters:
x System Frequency
x Time Error
x End of Day checkouts
x End of Month billing
Thus, no confusion would result and this should be deleted form the rationale
The Rationale for Requirement R8 also states “The intent of Requirement R8 is to provide accuracy
in the measurement and calculations.” Common source metering does not provide accuracy as
the data can still be in error. What common source metering does provide is a zero-sum system.
Thus, the SRC requests that the rationale be modified to more accurately reflect the impact of
data sources on accuracy.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
13
5. Please provide any issues you have on the proposed change to the BAL-006-3 standard and a
proposed solution.
Comments:
The SRC recommends that BAL-006 be retired.
Rationale:
Inadvertent Interchange is an accounting metric not reliability metric.
The BAL-006 requirements are administrative mandates related to after-the-fact accounting
should be retired under Paragraph 81.
Any value of Inadvertent Interchange is as an internal control process and would best be
memorialized in a form other than a standard.
6. Please provide any issues you have on the proposed change to the FAC-001-3 standard and a
proposed solution.
Comments:
The SRC recommends that FAC-001-2 be retired (also see response to Question 2 above)
Rationale:
1. Requirements R1 – R4 address administrative items that are generally contained within
Interconnection Agreements as legal terms and conditions – not as reliability-related concerns
or issues
2. Requirements R5-R7 are certification issues. If these requirements were reliability standards,
they would result in an unnecessary annual exchange of paperwork between and among asset
owners, BAs and the ERO.
Unofficial Comment Form
Project 2010-14.2.1 BARC | July-September, 2015
14
AssociatedBallot:2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControlsBALͲ005Ͳ1,BALͲ006Ͳ3&FACͲ001Ͳ3IN1ST
CommentPeriodEndDate:9/14/2015
CommentPeriodStartDate:7/30/2015
ProjectName:2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControls|BALͲ005Ͳ1,BALͲ006Ͳ3&FACͲ001Ͳ3
Consideration of Comments
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
1
2. TheSDThasmovedtheBALͲ005Ͳ0.2bRequirementR1toFACͲ001sinceitprovidesforidentifyinginterconnectionFacilities
andnotforcalculatingReportingACE.DoyouagreewithmovingthisrequirementintotheFACͲ001Ͳ3standard?Ifnot,
pleaseexplaininthecommentareabelow.
1. TheSDThasmodifiedthedefinitionofAutomaticGenerationControl(AGC).Doyouagreethatthismodifieddefinition
betterrepresentstheSDTintenttomakingresourcesmoreinclusivethanjustthetraditionalgenerationresources?Ifnot,
pleaseexplaininthecommentareabelow.
Questions
Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogiveeverycommentserious
considerationinthisprocess.Ifyoufeeltherehasbeenanerrororomission,youcancontacttheDirectorofStandards,Howard
Gugel(viaemail)orat(404)446Ͳ9693.
Therewere46setsofresponses,includingcommentsfromapproximately131differentpeoplefromapproximately87different
companiesrepresenting9ofthe10IndustrySegmentsasshownonthefollowingpages.
Allcommentssubmittedcanbereviewedintheiroriginalformatontheprojectpage.
1—TransmissionOwners
2—RTOs,ISOs
3—LoadͲservingEntities
4—TransmissionͲdependentUtilities
5—ElectricGenerators
6—ElectricityBrokers,Aggregators,andMarketers
7—LargeElectricityEndUsers
8—SmallElectricityEndUsers
9—Federal,State,ProvincialRegulatoryorotherGovernmentEntities
10—RegionalReliabilityOrganizations,RegionalEntities
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
6. PleaseprovideanyissuesyouhaveontheproposedchangetotheFACͲ001Ͳ3standardandaproposedsolution.
5. PleaseprovideanyissuesyouhaveontheproposedchangetotheBALͲ006Ͳ3standardandaproposedsolution.
4. PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ005Ͳ1standardandaproposedsolution.
3. TheSDThasmovedtheBALͲ006Ͳ2RequirementR3intoBALͲ005Ͳ3sincethisrequirementdirectlyimpactsanentity’s
abilitytocalculateanaccurateReportingACE.DoyouagreewithmovingthisrequirementintotheproposedBALͲ005Ͳ1
standard?Ifnot,pleaseexplaininthecommentareabelow.
The Industry Segments are:
2
3
1.TheSDThasmodifiedthedefinitionofAutomaticGenerationControl(AGC).Doyouagreethatthismodifieddefinitionbetter
representstheSDTintenttomakingresourcesmoreinclusivethanjustthetraditionalgenerationresources?Ifnot,please
explaininthecommentareabelow.
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
SelectedAnswer:
Yes
AndrewPusztaiͲAmericanTransmissionCompany,LLCͲ1Ͳ
SelectedAnswer:
Yes
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
Yes
RichardVineͲCaliforniaISOͲ2Ͳ
AnswerComment:
TheCaliforniaISOsupportsthecommentsoftheISO/RTOCouncil
StandardsReviewCommitteeforallquestionsinthisSurvey.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
JeremyVollͲBasinElectricPowerCooperativeͲ3Ͳ
SelectedAnswer:
Yes
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
SelectedAnswer:
Yes
EmilyRousseauͲMROͲ1,2,3,4,5,6ͲMRO
GroupName:
MROͲNERCStandardsReviewForum(NSRF)
GroupMemberName
Entity
JoeDepoorter
MadisonGas&Electric
AmyCasucelli
XcelEnergy
ChuckLawrence
AmericanTransmissionCompany
ChuckWicklund
OtterTailPowerCompany
TheresaAllard
MinnkotaPowerCooperative,Inc
DaveRudolph
BasinElectricPowerCooperative
KayleighWilkerson
LincolnElectricSystem
JodiJenson
WesternAreaPower
Administration
LarryHeckert
AlliantEnergy
MahmoodSafi
OmahaPublicUtilityDistrict
ShannonWeaver
MidwestISOInc.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
MRO
MRO
MRO
Regio
n
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
4
1,3,5,6
2
Segme
nts
3,4,5,6
1,3,5,6
1
1,3,5
1,3,5,6
1,3,5,6
1,3,5,6
1,6
4
MikeBrytowski
BradPerrett
ScottNickels
TerryHarbour
TomBreene
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
SelectedAnswer:
Likes:
Dislikes:
TonyEddleman
SelectedAnswer:
AnswerComment:
Yes
0
1
5
DTEEnergyͲDetroitEdisonCompany,5,DePriestJeffrey
GreatRiverEnergy
MRO 1,3,5,6
MinnesotaPower
MRO 1,5
RochesterPublicUtilities
MRO 4
MidAmericanEnergyCompany
MRO 1,3,5,6
WisconsinPublicService
MRO 3,4,5,6
Corporation
NebraskaPublicPowerDistrict
MRO 1,3,5
Yes
WeagreeitmakesAGCmoreinclusiveandunderstandtherewasa
FERCdirectivetomakethischange,butthedirectivedoesnotaddto
reliability.
Thankyouforyouraffirmativeresponseandclarifyingcomment.The
SDThasfurthermodifiedthedefinitionofAGC.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AmyCasuscelliͲXcelEnergy,Inc.Ͳ1,3,5,6ͲMRO,WECC,SPP
SelectedAnswer:
Yes
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio
n
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
JohnCiza
SouthernCompanyGeneration
SERC
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC
WilliamShultz
SouthernCompanyGeneration
SERC
SelectedAnswer:
Yes
EleanorEwryͲPugetSoundEnergy,Inc.Ͳ1,3,5ͲWECC
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
3
5
Segme
nts
1
6
6
BobSolomon
GroupMemberName
GingerMercier
BillHutchison
MichaelBrytowski
EllenWatkins
JohnShaver
JohnShaver
RyanStrom
ScottBrame
BillWatson
SelectedAnswer:
AnswerComment:
Regio
n
RFC
Segme
nts
1
HoosierEnergyRuralElectric
Cooperative,Inc.
PrairiePower,Inc.
SERC 1,3
SouthernIllinoisPower
SERC 1
Cooperative
GreatRiverEnergy
MRO 1,3,5,6
SunflowerElectricPower
SPP
1
Corporation
ArizonaElectricPower
WECC 4,5
Cooperative,Inc.
SouthwestTransmission
WECC 1
Cooperative,Inc.
BuckeyePower,Inc.
RFC
4
NorthCarolinaElectric
SERC 3,4,5
MembershipCorporation
OldDominionElectricCooperative SERC 3,4
Yes
Weagreethatthemodifieddefinitionisastepintheright
direction.However,thedefinitionreferencesDemandResponsein
capitalletters.Whilethatconceptisrecognizedbyindustry,itofficially
isnotaNERCGlossaryTerm.WerecommendthatSDTrephrasethe
lastsentenceofthisdefinitiontoread“ResourcesutilizedunderAGC
mayinclude,butnotbelimitedto,conventionalgeneration,variable
energyresources,energystoragedevices,anddemandresponse
resources.”
Entity
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
7
Response:
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
SelectedAnswer:
No
AnswerComment:
TexasREdoesagreethatthereviseddefinitionismore
inclusive.Thereisaconcern,however,aboutdisregarding
asynchronousTieMWsinthecalculationforReportingACE.Ifa
BalancingAuthority(BA)has1000MWsofgenerationand500MWSof
loadwiththeremaininggenerationbeingtransferredasynchronously,
howwilltheACEequation,andsubsequentlyAGC,workproperly?
TheReportingACEequationaccountsforallgenerationandload.Any
asynchronousTieMWstoanotherInterconnectionisaccountedas
eitherloadorgenerationincludingsuchtransfers.
WiththereviseddefinitionofReportingACE,itappearstheStandard
DraftingTeam(SDT)isdisregardingsingleBAInterconnections,suchas
ERCOTandQuebec.TexasREisconcernedaboutthestatement“All
NERCInterconnectionswithmultipleBalancingAuthorityAreasoperate
usingtheprinciplesofTieͲbias(TLB)Controlandrequirementtheuseof
Thankyouforyourcomments.TheSDThasmadechangesto
thedefinitionofAGCtohelpresolvethisissue.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
8
9
anACEequationsimilartotheReportingACEdefinedabove.”This
statementimpliesthatsingleBAInterconnections,suchasERCOTand
QuebecdonotoperateusingtheprinciplesofTLBandtheuseof
ACE.Ifnot,howdoesBALͲ001apply?Isindicatingan“alternative”
methodforaReportingACEequationuseadvocatingregional
differences?
TheSDTbelievestheReportingACEstillisapplicabletoasingle
BAinterconnectionusingtheprinciplesofTieͲbiascontrol.
However,theSDThasmadethefollowingmodification:
AllNERCInterconnectionsoperateusingtheprinciplesofTieͲline
Bias(TLB)ControlandrequiretheuseofanACEequationsimilar
totheReporting ACEdefinedabove.
TexasREinquiresastowhetheritistheSDT’sintentthatAGC(as
currentlydefinedintheproposeddefinition)willbeonlyfrequencyͲ
basedforsingleͲbalancingauthorityareas.
ThedefinitiondoesnotchangehowoneusesAGCnordoesitchange
theapplicableNERCReliabilityStandards.InadditiontheSDThas
modifiedthedefinitiontoaddclarity.Pleaserefertoourresponsesto
Question#4foradditionalinformation.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
SelectedAnswer:
Yes
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
SelectedAnswer:
Yes
CarolChinnͲFloridaMunicipalPowerAgencyͲ4Ͳ
GroupName:
FMPA
GroupMemberName
Entity
TimBeyrle
CityofNewSmyrnaBeach
JimHoward
LakelandElectric
GregWoessner
KissimmeeUtilityAuthority
LynneMila
CityofClewiston
JavierCisneros
FortPierceUtilityAuthority
RandyHahn
OcalaUtilityServices
DonCuevas
BeachesEnergyServices
StanRzad
KeysEnergyServices
MattCulverhouse
CityofBartow
TomReedy
FloridaMunicipalPowerPool
StevenLancaster
BeachesEnergyServices
MikeBlough
KissimmeeUtilityAuthority
MarkBrown
CityofWinterPark
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Regio
n
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
Segme
nts
4
3
3
3
4
3
1
4
3
6
3
5
3
10
MaceHunter
LakelandElectric
FRCC 3
SelectedAnswer:
No
AnswerComment:
FMPAsupportsusingthetermresourcestomakethedefinitionmore
inclusive,butthecapitalizedtermDemandResponseisnotintheNERC
glossaryofterms.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
Yes
AnswerComment:
PJMfindsthatthemodifieddefinitionofAGCisinclusiveofmore
resourcetypesthanonlytraditionalgenerationresources.However,
AGCequipmentdoesnotdirectlyadjusttheoutputofresources,but
insteadgeneratesandsendscontrolsignalstotheresourcestochange
output.PJMsuggeststhefollowingchangetothedefinitionforclarity:
AutomaticGenerationControl(AGC):Centrallylocatedequipmentthat
generatesandsendscontrolsignalstoautomaticallyadjustsresources
inaBalancingAuthorityAreatohelpmaintaintheReportingACEinthat
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
11
12
ofaBalancingAuthorityAreawithintheboundsrequiredbyapplicable
NERCReliabilityStandards.ResourcesutilizedunderAGCmayinclude,
butarenotlimitedto,conventionalgeneration,variableenergy
resources,storagedevicesandloadsactingasresources(suchas
DemandResponse).
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
Response:
ChantalMazzaͲHydroͲQu?becTransEnergieͲ2ͲNPCC
SelectedAnswer:
Yes
AnswerComment:
AGCisnolongerusedinBALͲ005Ͳ1,thereforeHQquestionswhether
Project2010Ͳ14.2.1isthebestopportunitytorevisethisdefinition.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.However,sinceAGCadjustmentimpacts
ReportingACE,andReportingACEiscriticalforBALͲ005,theSDT
feltitwasappropriatetoadjustthedefinitionunderthisprocess.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
TheresaRakowskyͲPugetSoundEnergy,Inc.Ͳ1Ͳ
SelectedAnswer:
Yes
AnswerComment:
Themodificationisonthecorrecttracktoexpandthedefinition.
Response:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio Segme
n
nts
DougHils
DukeEnergy
RFC
1
LeeSchuster
DukeEnergy
FRCC 3
DaleGoodwine
DukeEnergy
SERC 5
GregCecil
DukeEnergy
RFC
6
SelectedAnswer:
Yes
AnswerComment:
DukeEnergyrecommendsthatthedraftingteamclarifyorstatethat
justbecauseatermappearsinadefinitiondoesnotmakethe
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
13
14
definitionapplicabletosaidterm.Forexample,theterm“Demand
Response”appearsintheproposeddefinitionofAutomatic
GenerationControl(AGC),however,AGCdoesnotadjustDemand
Response.Clarificationisneededfromthedraftingteamstatingthat
justbecausethistermappearsinthedefinition,thisdoesn’tmean
everytypeofGeneratingResource,LoadResource,orLoadreactingas
aresourceiscapableofprovidingresponsetoanAGCsignal.Just
becauseatermislistedinthedefinition,doesn’tmeanitshould
qualifyasanexample.Wesuggestthedraftingteamrevisethe
languagetoinclude“suchasqualifieddemandresources”ratherthan
“DemandResponse”whichcanmeanalotofdifferentthings.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
Response:
AndreaBasinskiͲPugetSoundEnergy,Inc.Ͳ3Ͳ
SelectedAnswer:
No
BrentIngebrigtsonͲLG&EandKUEnergy,LLCͲ1,3,5,6ͲSERC
GroupName:
LG&EandKUEnergy,LLC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Entity
Regio
n
SERC
SERC
SERC
SERC
SERC
Segme
nts
1,3,5,6
1,3,5,6
3
6
5
BrentIngebrigtson
LG&EadnKUenergy,LLC
justinBencomo
LG&EandKUEnergy,LLC
ChjarlieFreibert
LG&EandKUEnergy,LLC
LinnOelker
LG&EandKUEnergy,LLC
DanWilson
LG&EandKUEnergy,LLC
SelectedAnswer:
No
AnswerComment:
ThesecommentsaresubmittedonbehalfLG&EandKUEnergy,LLC
(LG&E/KU).LG&E/KUisregisteredintheSERCRegionforoneormore
ofthefollowingNERCfunctions:BA,DP,GO,GOP,IA,LSE,PA,RP,TO,
TOP,TP,andTSP
Comments:
Makingadefinition“moreinclusive”doesnotmakeitcleareror
better.Infact,anargumentcanbemadethatan“inclusive”definition
canbecomeproblematic.Theproposeddefinitionincludes
uneccessary,prescriptivelanguageonwhattypesofresourcesmaybe
usedforAGC.Weareconcernedthatthelistwillraiseexpectations
thatVERs,storagedevicesandDemandResponseresourcesshouldbe
includedinanentity’sAGCfunction.ManyDemandResponse
programs(suchasresidentialloadinterruption)arenotcompatiblewith
AGCoperationsandshouldnotbeconsideredassuch.
Thelastsentenceoftheproposeddefinitionisnotnecessary,reduces
theclarityofthedefinitionandshouldbedeleted.
GroupMemberName
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
15
16
AutomaticGenerationControl(AGC):Centrallylocatedequipmentthat
generatesandsendscontrolsignalstoautomaticallyadjustresourcesin
aBalancingAuthorityAreatohelpmaintaintheReportingACEinthatof
aBalancingAuthorityAreawithintheboundsrequiredbyapplicable
NERCReliabilityStandards.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
Response:
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,
3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
SelectedAnswer:
Yes
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
LeePedowiczͲNortheastPowerCoordinatingCouncilͲ10ͲNPCC
GroupName:
NPCCͲͲProject2010Ͳ14.2.1Phase2ofBalAuthRelͲbasedControls
ͲBALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
GroupMemberName
Entity
Regio Segme
n
nts
AlanAdamson
NewYorkStateReliabilityCouncil, NPCC 10
LLC
DavidBurke
OrangeandRocklandUtilitiesInc. NPCC 3
GregCampoli
NewYorkIndependentSystem
NPCC 2
Operator
GerryDunbar
NortheastPowerCoordinating
NPCC 10
Council
MarkKenny
NortheastUtilities
NPCC 1
HelenLainis
IndependentElectricitySystem
NPCC 2
Operator
RobVance
NewBrunswickPowerCorporation NPCC 9
PaulMalozewski
HydroOneNetworksInc.
NPCC 1
BruceMetruck
NewYorkPowerAuthority
NPCC 6
LeePedowicz
NortheastPowerCoordinating
NPCC 10
Council
DavidRamkalawan
OntarioPowerGeneration,Inc.
NPCC 5
BrianRobinson
UtilityServices
NPCC 8
WayneSipperly
NewYorkPowerAuthority
NPCC 5
EdwardBedder
OrangeandRocklandUtilitiesInc. NPCC 1
MichaelJones
NationalGrid
NPCC 1
BrianShanahan
NationalGrid
NPCC 1
GlenSmith
EntergyServices,Inc.
NPCC 5
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
17
ConnieLowe
GuyZito
SilviaParadaMitchell
RobertPellegrini
KathleenGoodman
SelectedAnswer:
AnswerComment:
RuiDaShu
NortheastPowerCoordinating
NPCC 10
Council
DominionResourcesServices,Inc. NPCC 5
NortheastPowerCoordinating
NPCC 10
Council
NextEraEnergy,LLC
NPCC 5
TheUnitedIlluminatingCompany NPCC 1
ISOͲNewEngland
NPCC 2
No
Theuseofcentrallylocatedequipment,thatautomaticallyadjusts,
maintainReportingACE,resourcesutilizedunderAGCneedstobe
considered.
ThereisnojustificationtolinkthedefinitionofAutomaticGeneration
Control(AGC)toagivenlocation.
AGCisnothardware(equipment);AGCissoftware.
AGCdoesnot“adjustresources”(thatisusuallyaccomplishedatthe
resourceitself).AGC“isusedtoadjustresources”.
AGCisnotdesignedforreportingpurposes.AGCisdesigntoassistin
thecontrolofaBA’sbalanceofitsresourcestoitsNERCmandated
balancingobligations.
Proposethatthedefinitionberevisedto:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
18
19
AutomaticGenerationControl(AGC):Softwaredesignedandusedto
adjustaBalancingAuthority’sresourcestomeettheBA’sbalancing
requirementsasrequiredbyapplicableNERCReliabilityStandards.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
BALͲ005beingaNERCstandardandnotoneofthemanyregionallyͲ
approvedstandardsisapplicabletoallBasunlesstheBAisinaregionin
whichthestandardissupersededbyaFERCͲapprovedregional
standard.AutomaticTimeErrorCorrectionisnotapartoftheFERCͲ
approvedstandardsforallBas.ForclaritytheregionallyͲapproved
definitionandreferencestoAutomaticTimeErrorCorrection(IATEC)
bedeletedandlefttoanapprovedregionalstandard.
UndertheFERCOrderapprovingBALͲ001Ͳ2(RealPowerBalancing
ControlPerformance)NERCwasdirectedtoincludeATECintheACE
equation.SinceReportingACEincludesthedefinitionfortheWestern
Interconnection,ATECmustbedefinedandincludedinthedefinitions.
TheReportingACEdefinitionwasbrokenintosubͲdefinitionstoeasily
managethespecificReportingACEequationforeachInterconnection,
suchastheATECtermfortheWesternInterconnection.
Response:
MikeONeilͲNextEraEnergyͲFloridaPowerandLightCo.Ͳ1Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
SelectedAnswer:
Yes
PayamFarahbakhshͲHydroOneNetworks,Inc.Ͳ1Ͳ
SelectedAnswer:
No
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
GroupName:
ISOStandardsReviewCommittee
GroupMemberName
Entity
Regio Segme
n
nts
CharlesYeung
SPP
SPP
2
BenLi
IESO
NPCC 2
MarkHolman
PJM
RFC
2
KathleenGoodman
ISONE
NPCC 2
GregCampoli
NYISO
NPCC 2
AliMiremadi
CAISO
WECC 2
TerryBilke
MISO
RFC
2
ChristinaBigelow
ERCOT
TRE
2
SelectedAnswer:
No
AnswerComment:
TheSRCdoesnotagreewiththeproposeddefinitionofAGC.
TheSRCrecommendsthefollowingdefinitionforAGC:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
20
21
AutomaticGenerationControl(AGC):Aprocessdesignedandusedto
adjustaBalancingAuthority’sresourcestomeettheBA’sbalancing
requirementsasrequiredbyapplicableNERCReliabilityStandards.
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
SeeattachedforthefulltextofthecommentstoQuestions1Ͳ6
Response:
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
Yes
ShawnaSpeerͲColoradoSpringsUtilitiesͲ1Ͳ
GroupName:
ColoradoSpringsUtilities
GroupMemberName
Entity
Regio Segme
n
nts
ShawnaSpeer
ColoradoSpringsUtilities
WECC 1
ShannonFair
ColoradoSpringsUtilities
WECC 6
CharlesMorgan
ColoradoSpringsUtilities
WECC 3
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
KalebBrimhall
ColoradoSpringsUtilities
WECC 5
SelectedAnswer:
Yes
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
GroupName:
SPPStandardsReviewGroup
GroupMemberName
Entity
Regio Segme
n
nts
ShannonMickens
SouthwestPowerPool
SPP
2
JasonSmith
SouthwestPowerPool
SPP
2
AshleyStringer
OklahomaMunicipalPower
SPP
4
Authority
SelectedAnswer:
No
AnswerComment:
Theaddedsentenceattheendofthedefinitionadequatelyservesthe
purposeofclarifyingthatall“resources”areincludedratherthanjust
traditionalgenerators.Thechangetoaddthedescriptor“Centrally
located”whendescribingthe“equipment”isalsoproblematic.There
doesnotappeartobeastatedjustificationformakingthatchangeand
itcouldintroduceissuesininterpretationsurroundingredundant
systemsorsubͲsystemsthatcouldorshouldbeincludedinthesystem
thatisusedforAGC.Ifthereisareasonforcontinuingtoincludethe
“centrallylocated”descriptor,wesuggestthattheSDTclarifythe
reason.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
22
23
TheSDThasmadechangestothedefinitionofAGCtohelp
resolvethisissue.
Response:
ErikaDootͲU.S.BureauofReclamationͲ5Ͳ
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
24
GeneralResponseoftheSDTtocommentsreceived:
HasthereeverbeenasituationwhereLoadwasnotwithinaBAmeteredboundary?Theanswertothisquestionisyes,butitis
thewrongquestion.Thecorrectquestionis,“CantheadditionofanewloadwithoutnoticetotheBAaffecttheabilityofaBAto
performitsbalancingfunctionadequatelyandthusdetrimentallyaffectreliability?”
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincludedtomeetthegeneralrequirementforTieLineBias
Controltobeeffective.IntheNERCGlossaryofTerms,ReportingACErequiresthat,“AllportionsoftheInterconnectionare
includedinonearea[BAA]oranothersothatthesumofallareageneration,loadsandlossesisthesameastotalsystem
generation,loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.Thenewversionofthestandard
addressesthisreliabilityconcernthroughamodificationtothedefinitionofReportingACErequiringthatActualNetInterchange
andScheduledNetInterchangeonlyincludeinterchangewithotherBAAs.BymodifyingthedefinitionofReportingACEit
becomesimpossibletoexcludeanygenerator,transmission,orloadfromallBAAsonaninterconnectionbecauseexclusionfrom
oneBAAcanonlybeaccomplishedbytransferringthatgenerator,transmissionorloadtoanadjacentBAA.Inaddition,
inadvertentaccountingfromthenewBALͲ005Ͳ1R7willrevealanyproblemsbetweenScheduledNetInterchangeascomparedto
ActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTDrealizedthatthereisnorequirementthattheBAbe
informedofthenewfacilitiestobeinterconnectedbeforetheactualinterconnectionwouldtakeplace.ThisputstheBAinthe
unreasonablepositionofhavingtoadjustitsoperationsfornewunknowngeneration,transmissionorloadwithoutadvanced
notice.TheintentoftheadditionstoR3andR4toFACͲ001istoinsurethattheBAreceivesadvancednoticeofthe
interconnection.ThisisaoneͲtimerequirementsincethechangeinthedefinitionofReportingACEaddressedtheintentofthe
originalBALͲ005Ͳ0R1andtheongoingreliabilityissue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
2.TheSDThasmovedtheBALͲ005Ͳ0.2bRequirementR1toFACͲ001sinceitprovidesforidentifyinginterconnectionFacilities
andnotforcalculatingReportingACE.DoyouagreewithmovingthisrequirementintotheFACͲ001Ͳ3standard?Ifnot,
pleaseexplaininthecommentareabelow.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
25
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthatwouldrequirematerialfacilitychanges,and
thereforematerialchangesintheloadtobebalanced.
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
SelectedAnswer:
Yes
AndrewPusztaiͲAmericanTransmissionCompany,LLCͲ1Ͳ
SelectedAnswer:
Yes
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
Yes
ThomasFoltzͲAEPͲ5Ͳ
SelectedAnswer:
No
AnswerComment:
WedonotagreethatFACͲ001isthecorrectstandardtohousethese
obligations.FACͲ001appliestotheinterconnectionofnewfacilities,while
theR5,R6&R7RequirementstakenfromBALͲ005Ͳ0.2bapplytoall
Transmission,Generation&Loadfacilities.
ResponsetoComment:
26
TheSDTproposedchangestoFACͲ001,asitdoesnotsolelyapplytothe
interconnectionofnewfacilities,butitalsorequiresnotificationof“newor
materiallymodifiedexistinginterconnections”.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
27
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
Intheeventthatthedraftingteam*is*successfulinmovingthese
obligationstoFACͲ001,thenewrequirementswillneedtobeclarifiedsothat
therequirementsapplyonlytonewinterconnectingfacilities(consistentwith
thespiritoftheotherFACͲ001requirements).Inthatcase,separate
requirementswillstillberequiredelsewheretoapplytoexisting
Transmission,Generation&Loadfacilities.Inaddition,itwouldalsobe
incumbentontheTOtoensurethatthewordingfortheseobligationsare
explicitwithintheirinterconnectagreementsandthenecessaryinterconnect
guidesthatarespecifiedinFACͲ001.
TheSDTagreesthattherequirementsshouldbereͲwordedandhasmade
thenecessarymodifications.
AEP’sdecisiontovotenegativeonthisproposalisdrivenbytheseobjections.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
Response:
TammyPorterͲTammyPorterOnBehalfof:RodKinard,OncorElectricDelivery,1
SelectedAnswer:
Yes
LouisSladeͲDominionͲDominionResources,Inc.Ͳ6Ͳ
GroupName:
Dominion
GroupMemberName
Entity
RandiHeise
NERCCompliancePolicy
ConnieLowe
NERCCompliancePolicy
LouisSlade
NERCCompliancePolicy
ChipHumphrey
PowerGenerationCompliance
NancyAshberry
PowerGenerationCompliance
LarryNash
ElectricTransmissionCompliance
CandaceLMarshall
ElectricTransmissionCompliance
LarryWBateman
TransmissionCompliance
JeffreyNBailey
NuclearCompliance
RussellDeane
NuclearCompliance
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
28
Region Segments
NPCC 5,6
SERC
1,3,5,6
RFC
5,6
SERC
5
RFC
5
SERC
1,3
SERC
1,3
SERC
1,3
SERC
5
NPCC 5
29
SelectedAnswer:
Yes
JeremyVollͲBasinElectricPowerCooperativeͲ3Ͳ
SelectedAnswer:
No
Itisnotnecessarytomovethisrequirement.TheSDTistakingaflawed
AnswerComment:
requirementandmovingittoanotherlocation.Therequirementshouldbe
improvedasfollows.
R1.Allgeneration,transmission,andloadoperatingwithinan
Interconnectionmustbeincludedwithinthemeteredboundariesofa
BalancingAuthorityArea.
Therequirementabovewasaconcept(ControlAreaCriteria)thatwasswept
intotheV0standard.Theonlywaytoprovethateverythingiswithinthe
meteredboundsofaBAisviaInadvertentInterchangeaccounting.R1
shouldbekeptasͲis,thesubͲbulletsremovedandthemeasureforR1should
be:
ResponsetoComment:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
30
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
M1.TheBalancingAuthoritywasunabletoagreewithanAdjacentBalancing
AuthoritywhenperformingInadvertentInterchangeaccountinganditwas
foundthattheBalancingAuthorityhadanerrorinitsmodelortielinesthat
misstateditsNetActualInterchangevalueinitsInadvertentInterchange
accounting.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
Response:
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
SelectedAnswer:
Yes
EmilyRousseauͲMROͲ1,2,3,4,5,6ͲMRO
GroupName:
MROͲNERCStandardsReviewForum(NSRF)
GroupMemberName
Entity
JoeDepoorter
MadisonGas&Electric
AmyCasucelli
XcelEnergy
ChuckLawrence
AmericanTransmissionCompany
ChuckWicklund
OtterTailPowerCompany
TheresaAllard
MinnkotaPowerCooperative,Inc
DaveRudolph
BasinElectricPowerCooperative
KayleighWilkerson
LincolnElectricSystem
JodiJenson
WesternAreaPowerAdministration
LarryHeckert
AlliantEnergy
MahmoodSafi
OmahaPublicUtilityDistrict
ShannonWeaver
MidwestISOInc.
MikeBrytowski
GreatRiverEnergy
BradPerrett
MinnesotaPower
ScottNickels
RochesterPublicUtilities
TerryHarbour
MidAmericanEnergyCompany
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
31
Region Segments
MRO 3,4,5,6
MRO 1,3,5,6
MRO 1
MRO 1,3,5
MRO 1,3,5,6
MRO 1,3,5,6
MRO 1,3,5,6
MRO 1,6
MRO 4
MRO 1,3,5,6
MRO 2
MRO 1,3,5,6
MRO 1,5
MRO 4
MRO 1,3,5,6
TonyEddleman
SelectedAnswer:
AnswerComment:
TomBreene
32
WisconsinPublicService
MRO 3,4,5,6
Corporation
NebraskaPublicPowerDistrict
MRO 1,3,5
No
Seeattachmentwithstrikethrough.
Itisnotnecessarytomovethisrequirement.TheSDTistakingaflawed
requirementandmovingittoanotherlocation.Therequirementshouldbe
improvedasfollows.
R1.Allgeneration,transmission,andloadoperatingwithinan
Interconnectionmustbeincludedwithinthemeteredboundariesofa
BalancingAuthorityArea.
R1.1.EachGeneratorOperatorwithgenerationfacilitiesoperatinginan
Interconnectionshallensurethatthosegenerationfacilitiesareincluded
withinthemeteredboundariesofaBalancingAuthorityArea.
R1.2.EachTransmissionOperatorwithtransmissionfacilitiesoperatingin
anInterconnectionshallensurethatthosetransmissionfacilitiesareincluded
withinthemeteredboundariesofaBalancingAuthorityArea.
R1.3.EachLoadͲServingEntitywithloadoperatinginanInterconnectionshall
ensurethatthoseloadsareincludedwithinthemeteredboundariesofa
BalancingAuthorityArea.
Therequirementabovewasaconcept(ControlAreaCriteria)thatwas
sweptintotheV0standard.Theonlywaytoprovethateverythingis
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
33
withinthemeteredboundsofaBAisviaInadvertentInterchange
accounting.R1shouldbekeptasͲis,thesubͲbulletsremovedandthe
measureforR1shouldbe:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3,andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
34
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
M1.TheBalancingAuthoritywasunabletoagreewithanAdjacent
BalancingAuthoritywhenperformingInadvertentInterchangeaccounting
anditwasfoundthattheBalancingAuthorityhadanerrorinitsmodelor
tielinesthatmisstateditsNetActualInterchangevalueinitsInadvertent
Interchangeaccounting.
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
SelectedAnswer:
No
AnswerComment:
Itisnotnecessarytomovethisrequirement.Therequirementcanbe
improvedbykeepingitwhereitisandlimitingitto:
R1.Allgeneration,transmission,andloadoperatingwithinan
Interconnectionmustbeincludedwithinthemeteredboundariesofa
BalancingAuthorityArea.
TherequirementisaconceptfromtheNERCOperatingManual(ControlArea
Criteria)thatwassweptintotheV0standard.Thereisonlyonewaytoprove
thateverythingiswithinthemeteredboundsofaBA,thatisthrough
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
35
InadvertentInterchangeaccounting.Thusthemeasureforthisrequirement
shouldbe:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
36
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
M1.TheBalancingAuthoritywasunabletoagreewithanAdjacentBalancing
AuthoritywhenperformingInadvertentInterchangeaccountinganditwas
AnswerComment:
foundthattheBalancingAuthorityhadanerrorinitsmodelortielinesthat
misstateditsNetActualInterchangevalueinitsInadvertentInterchange
accounting.
Response:
AmyCasuscelliͲXcelEnergy,Inc.Ͳ1,3,5,6ͲMRO,WECC,SPP
SelectedAnswer:
No
AnswerComment:
BALͲ005Ͳ0.2bR1shouldremainwhereitis,butwouldbeimprovedbythe
removalofthesubRequirements.Theonlymeanstoprovethateverything
iswithinthemeteredboudariesofaBalancingAuthorityisthrough
InadvertentInterchangeaccounting.
TherevisedR1shouldread:R1.Allgeneration,transmission,andload
operatingwithinanInterconnectionmustbeincludedwithinthemetered
boundariesofaBalancingAuthorityArea.
ResponsetoComment:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
37
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
ThemeasureM1shouldread:M1.TheBalancingAuthoritywasunableto
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
38
agreewithanAdjacentBalancingAuthoritywhenperformingInadvertent
AnswerComment:
InterchangeaccountinganditwasfoundthattheBalancingAuthorityhadan
errorinitsmodelortielinesthatmisstateitsNetsActualInterchangevalue
initsInadvertentInterchangeaccounting.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Region Segments
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
1
JohnCiza
SouthernCompanyGenerationand SERC
6
EnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC
3
WilliamShultz
SouthernCompanyGeneration
SERC
5
SelectedAnswer:
No
AnswerComment:
WhilethereisagreementwiththeremovalofR1fromBALͲ005Ͳ0.2b,the
insertionof4.1.3,andR5ͲR7intoFACͲ001Ͳ2isnotrequired.Notificationof
anentitiesinclusionwithinaBalancingAuthority’smeteredboundariescan
beaccomplishedthroughtheNERCRulesofProcedure,Section500,FACͲ
001Ͳ2,proposedstandardTOPͲ003Ͳ3andexistingstandardIROͲ010Ͳ2.For
example,sufficientlatitudeexistswithinFACͲ001Ͳ2asapproved,fortheTO
toprovidenotificationto“thoseresponsibleforthereliabilityoftheaffected
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
39
system(s)ofnewormateriallymodifiedexistinginterconnections.”Through
thisrequirement,theTOcanprovidealistofnewormodifiedfacilities(such
asnewormodifiedload,transmissionandgeneratorconnections)tothe
TOP,BAandRC.
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
40
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
Response:
EleanorEwryͲPugetSoundEnergy,Inc.Ͳ1,3,5ͲWECC
SelectedAnswer:
No
AnswerComment:
Asworded,wedonotbelievetheserequirementsareappropriateforFACͲ
001Ͳ3.SinceFACͲ001Ͳ3appliestodocumentedFacilityinterconnection
requirements,itwouldbemoreappropriatetorequirethatthedocumented
interconnectionrequirementscontainlanguagestatingthattransmission,
generationandendͲuserinterconnectedFacilitiesmustbelocatedwithinthe
BalancingAuthorityArea’smeteredboundaries.Thiscouldbeaccomplished
byaddingR3.3stating“ProceduresforensuringthattransmissionFacilities,
generationFacilitiesandendͲuserFacilitiesarewithintheBalancing
AuthorityArea’smeteredboundaries.”Therequirementtoverifythat
existingfacilitiesarelocatedwiththemeteredboundariesofaBalancing
AuthorityAreaismostappropriatelyassignedtotheTOP,andnottotheTO,
GOandtheLSE.
ResponsetoComment:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
41
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
42
Response:
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Region Segments
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC
1,3
BillHutchison
SouthernIllinoisPowerCooperative SERC
1
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
JohnShaver
ArizonaElectricPowerCooperative, WECC 4,5
Inc.
JohnShaver
SouthwestTransmission
WECC 1
Cooperative,Inc.
RyanStrom
BuckeyePower,Inc.
RFC
4
ScottBrame
NorthCarolinaElectricMembership SERC
3,4,5
Corporation
BillWatson
OldDominionElectricCooperative
SERC
3,4
SelectedAnswer:
No
AnswerComment:
1.WeconcurthattheintentofBALͲ005Ͳ0.2bRequirementR1providesfor
identificationofInterconnectionFacilitiesandnotforthecalculationof
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
43
ReportingACE.WequestioniftheSDTfollowedtherecommendationsofthe
Project2010Ͳ14.2BALStandardsPRTto“exploreiftheroleoftheTOPwould
appropriatelycovertheloadsinterconnectedtothatTOPsuchthattheLSE
requirementmaynotbenecessary.”WeasktheSDTtoproviderationalefor
theproposedFACͲ001Ͳ3standardtoexplaintheirconclusiononwhythey
continuetolisttheLSEasanapplicableentity.WeremindtheSDTthatthe
retirementoftheLSEispendingFERCapprovalthroughtheRiskͲBased
Registration(RBR)initiative.WedonotunderstandwhytheSDTfeelslike
theLSEhasareliabilityrole,whentheEROcontinuestoarguethattheLSEis
primarilyfocusedoncommercialactivitiesandotherentities,suchasthe
TOP,wouldcontinuetomeetreliabilityneedswithouttheLSE.Westrongly
recommendthatthedraftingteamremovetheLSEfromtheapplicability
section.
2.Aslistedwithinthisproject’sSAR,theProject2010Ͳ14.2BALStandards
PRT“believesthattherequirementstoidentifytheapplicableBAshould
perhapsbeintheinterconnectionagreements(viaFERC’sOATTorNAESB,
forexample),”webelievetheserequirementsalreadydo.Manyother
reliabilityrequirementsintheTOPandIROstandardssupportthe
identificationofInterconnectionFacilitiesthroughdatamodelingand
specifications.Forexample,TOPͲ003Ͳ3R4identifiesthat“eachBalancing
Authorityshalldistributeitsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoring.”IfaBAneedsinformationregardingaparticularload,
generationresource,ortransmissionlineoperatingwithinitsBAArea,based
onthisrequirement,wouldtheynot“identify”thecorrectentitytosend
theirspecification?Furthermore,NERChasspentsignificanttimeand
resourcesonthedevelopmentoftheBESdefinitionandtheremovalofthe
LSEfromitsfunctionalmodel.Theseeffortswereaccomplishedtofocuson
entitiesandfacilitiesthatposedasignificantrisktoBESreliability.TheSDT
hasalreadyidentifiedthattheintentoftheserequirementsisnotforthe
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
44
calculationofReportingACEandonlytheidentificationof
entities.Moreover,ifagenerationresource,transmissionline,orloadisnot
properlyaccountedforinthecalculationofReportingACE,Inadvertent
InterchangewillresultandtheBAwouldinvestigatetocorrectthe
discrepancy,asabestpractice,accordingly.WerecommendtheSDTremove
theserequirementsfromtheproposeddraftstandards.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
45
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
JonathanAppelbaumͲUnitedIlluminatingCo.Ͳ1Ͳ
SelectedAnswer:
No
AnswerComment:
First,aquickreviewoftheStandardsshowsthereisnootherspecific
requirementtoensureafacilityisinameteredboundryortelemteryis
providedtoaRC,BA,orTOP.Thisrequirementistoensurethataloador
generatorismeteredandcommunicatedtoBAforBAfunction.Itisjustas
importantthatlinemeteringisreportedtoTOPandRC,yetthereisnoFAC
requirementtoinstallmeteringandtelemetry.ForTOPandRC,thereisTOPͲ
03andIROͲ010withadataspecificationandprocesstodeliverdata.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
ResponsetoComment:
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
ResponsetoComment:
AnswerComment:
46
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Second,FACͲ001isaboutdevelopingasingledocumentforoneͲtimeuseby
aninterconnectingentitytoknowwhatisrequiredtocompletean
interconnection.Theproposedchangecreatesanongoingrequirementto
conformthattheinterconnectionisinthemeteredboundariesofthe
BA.TheproposedrequirementisnotconsistentwithFACͲ001.Aconsistent
approachtoFACͲ001istorequirethattherequirementsaddressthe
meteringrequiredtofacilitatetheBAfunction,butthisisalreadyimpliedin
thecurrentFACͲ001Ͳ2standard.
TheSDThasmodifiedFACͲ001toaddressyourissue.
BalancingisbecomingacomplicatedfunctionascomparedtotheVersion0
days.TheBAshouldhaveitsowndataspecificationstandardsimilartoTOPͲ
003orIROͲ010.Inthealternativetheserequirementsshouldberetired,
withthecommentthattherequirementisimpliedalreadyinFAcͲ001Ͳ2and
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
47
theTechnicalandGuidelinesectionofFACͲ001Ͳ2willbeupdatedtoincludea
specificexplanationofincludinginterconnectioninBAmeteredboundary.
ThegoaloftheNERCReliabilityStandardsaretobeclearnottoimply
requirements.
ResponsetoComment:
Response:
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
SelectedAnswer:
No
AnswerComment:
TexasREnoticedthattheLoadͲServingEntity(LSE)functionwasaddedtothe
FACͲ001Ͳ3applicabilitybutisnotmentionedintheEvidenceRetention
section.
Thankyouforyourcomment.TheSDThasmadethenecessary
modifications.TheLSEhasbeenremovedfromthestandardbasedonthe
RBRinitiative.
TexasREnoticedtheterm,“TransmissionFacilities”iscapitalizedinR5but
notinR1.2.Theterm“TransmissionFacilities”isnotadefinedterminthe
NERCglossarysoitcouldcauseconfusionifcapitalized.
Thankyouforyourcomments,theSDThasincorporatedyoursuggestions.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
48
Response:
BobThomasͲIllinoisMunicipalElectricAgencyͲ4Ͳ
SelectedAnswer:
No
AnswerComment:
GiventhestronglysupportedrationalefordeactivatingtheLSEregistration
functionundertheRiskͲBasedRegistrationinitiative,Requirement1.3of
BALͲ005Ͳ0.2bshouldnotbemovedtoFACͲ001Ͳ3asRequirement7.The
necessityofretainingthislanguageforreliabilitypurposesshouldbe
reconsidered.[HasthereeverbeenasituationwhereLoadwasnotwithina
BAmeteredboundary?]Ifthislanguageisneededforreliability,analternate
functionalentityshouldbeidentified.
ResponsetoComment:
HasthereeverbeenasituationwhereLoadwasnotwithinaBAmetered
boundary?Theanswertothisquestionisyes,butitisthewrongquestion.
Thecorrectquestionis,“Cantheadditionofanewloadwithoutnoticetothe
BAaffecttheabilityofaBAtoperformitsbalancingfunctionadequatelyand
thusdetrimentallyaffectreliability?”
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
49
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
Response:
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
SelectedAnswer:
Yes
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
SelectedAnswer:
No
AnswerComment:
AmerensupportsMISO'scommentsforthisquestion
Response:
CarolChinnͲFloridaMunicipalPowerAgencyͲ4Ͳ
GroupName:
FMPA
GroupMemberName
Entity
Region Segments
TimBeyrle
CityofNewSmyrnaBeach
FRCC 4
JimHoward
LakelandElectric
FRCC 3
GregWoessner
KissimmeeUtilityAuthority
FRCC 3
LynneMila
CityofClewiston
FRCC 3
JavierCisneros
FortPierceUtilityAuthority
FRCC 4
RandyHahn
OcalaUtilityServices
FRCC 3
DonCuevas
BeachesEnergyServices
FRCC 1
StanRzad
KeysEnergyServices
FRCC 4
MattCulverhouse
CityofBartow
FRCC 3
TomReedy
FloridaMunicipalPowerPool
FRCC 6
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
50
51
StevenLancaster
BeachesEnergyServices
FRCC 3
MikeBlough
KissimmeeUtilityAuthority
FRCC 5
MarkBrown
CityofWinterPark
FRCC 3
MaceHunter
LakelandElectric
FRCC 3
SelectedAnswer:
No
AnswerComment:
FMPAbelievestheserequirementsshouldberetiredonthebasisthatthey
arecoveredbythedataspecificationrequirementsofBoardapprovedTOPͲ
003Ͳ3.WhileitmaybeappropriatetoincludetheconceptofmetersandBA
meteredboundariesinFacilityinterconnectionrequirements,ascurrently
wordedtheproposedrequirementsdonotfitwiththepurposeor
applicabilityofFACͲ001.
ResponsetoComment:
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
52
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
No
AnswerComment:
WithmovingBALͲ005Ͳ0.2bR1toFACͲ001R5andR6,therequirementhas
shiftedfrombeingaGeneratorandTransmissionOperatorfunctiontoa
GeneratorandTransmissionOwnerfunction.PJMquestionsandconsiders
consequenceswiththischange.PJMseeksclarityonthefollowingtopics:
GenerationOwners,TransmissionOwners,andLoadͲServingEntitieshaveno
requirementtosupplytheBalancingAuthoritywithdatathataffectstheACE
calculation.PJMproposesthefollowingchangestoFACͲ001R5,R6,andR7:
R5.EachTransmissionOwnerwithtransmissionFacilitiesoperatinginan
InterconnectionshallconfirmthateachtransmissionFacilityiswithina
BalancingAuthorityArea’smeteredboundaries.TheTransmissionOwner
shallcoordinateanychangescausedtotheACEduetoeachtransmission
FacilitywiththeimpactedBalancingAuthorities.
R6.EachGeneratorOwnerwithgenerationFacilitiesoperatinginan
InterconnectionshallconfirmthateachgenerationFacilityiswithina
BalancingAuthorityArea’smeteredboundaries.TheGenerationOwnershall
coordinateanychangescausedtotheACEduetoeachgenerationFacility
withimpactedBalancingAuthorities.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
53
R7.EachLoadͲServingEntitywithLoadoperatinginanInterconnectionshall
confirmthateachLoadiswithinaBalancingAuthorityArea’smetered
boundaries.TheLoadͲServingEntityshallcoordinatechangescausedtothe
ACEduetoeachLoadwithimpactedBalancingAuthorities.
TheLSEhasbeenremovedfromthestandardbasedontheRBRinitiative.
SinceReportingACEismadeupofmanycomponents,includingNetActual
Interchange(NIA),BalancingAuthoritieswillbedependentontheGenerator
Owners,TransmissionOwners,andLoadͲServingEntitiesforthisdata.When
ACEisimpactedbytheidentifiedInterconnectionFacilities,howshould
ReportingACEbeaddressedbytheBalancingAuthorityorReliability
Coordinator?IfaGenerator,TransmissionOwner,orloadͲServingEntityfail
toconfirmthateachoftheirFacilitiesarewithintheBalancingAuthority
Area’smeteredboundaries,istheaffectedBalancingAuthorityresponsible
forcalculatinganaccurateReportingACE?
ItistheresponsibilityofallBAAstocalculateReportingACEcorrectlyatall
times.Absentofmeteringoutgeneration,transmissionorloadwhichcannot
bedonewithouthavinganadjacentBAAinvolved,themeteringofthose
entitiesisnotusedinthecalculationofReportingACE.ThoughReporting
ACEmaybeaccurate,theBAmaynotbecapableofaccuratelyestimating
theirresourcerequirementstobalanceDemandandgeneration.TheLSEhas
beenremovedfromthestandardbasedontheRBRinitiative.
WhateffectswillthishaveonR5?WilltheBalancingAuthoritybeawaredata
fromtheGeneratorOwnerorTransmissionOwneraremissingorinvalidif
theGeneratorOwnerorTransmissionOwnerhavenotconfirmedit?
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
54
ThisistheholeinthestandardsthatmodificationstoFACͲ001R3andR4are
intendedtofill.
Response:
ChantalMazzaͲHydroͲQu?becTransEnergieͲ2ͲNPCC
SelectedAnswer:
No
AnswerComment:
FACͲ001isaboutFacilityInterconnectionRequirements.Intheapplication
guidelinesofFACͲ001Ͳ2,itismentionedthattheserequirementsinclude
meteringandtelecommunicationsandassuchcouldbeinterpretedto
alreadyincludearequirementofmeteringtotheBA.Meetingoffacility
interconnectionrequirementshoweveristhepurposeofFACͲ002Ͳ1.
Therefore2optionsareavailable:
1.ModifythepurposeofFACͲ001toincludetheGO,TOandLSE,DPorendͲ
usermeetingwithfacilityinterconnectionrequirements(whereaspresently
thepurposeisonlytomaketheserequirementsavailable)andaddinsection
B,requirementsfortheGO,TOandLSE,DPorendͲusertocomplywithall
requirementssetoutinR1thruR4(notonlywiththerequirementofbeing
withinaBA’smeteredboundariesasisthecasewithProject2010Ͳ14.2.1
proposal).RevisepurposeofFACͲ002Ͳ1sothatitaddressescoordination
studiesratherthanmeetingfacilityconnectionandperformance
requirements.
2.ChangethetitleofFACͲ002whichpresentlyisabitatoddswithits
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
55
purposeandaddrequirementsfortheGO,TOandLSE,DPorendͲuserto
complywithallrequirementssetoutinFACͲ001.
TheSDThasmodifiedFACͲ001toaddressyourconcerns.TheLSEhasbeen
removedfromthestandardbasedontheRBRinitiative.
Response:
TheresaRakowskyͲPugetSoundEnergy,Inc.Ͳ1Ͳ
SelectedAnswer:
No
AnswerComment:
Asworded,wedonotbelievetheserequirementsareappropriateforFACͲ
001Ͳ3.SinceFACͲ001Ͳ3appliestodocumentedFacilityinterconnection
requirements,itwouldbemoreappropriatetorequirethatthedocumented
interconnectionrequirementscontainlanguagestatingthattransmission,
generationandendͲuserinterconnectedFacilitiesmustbelocatedwithinthe
BalancingAuthorityArea’smeteredboundaries.Thiscouldbeaccomplished
byaddingR3.3stating“ProceduresforensuringthattransmissionFacilities,
generationFacilitiesandendͲuserFacilitiesarewithintheBalancing
AuthorityArea’smeteredboundaries.”Therequirementtoverifythat
existingfacilitiesarelocatedwiththemeteredboundariesofaBalancing
AuthorityAreaismostappropriatelyassignedtotheTOP,andnottotheTO,
GOandtheLSE.
ResponsetoComments:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
56
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
57
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Region Segments
DougHils
DukeEnergy
RFC
1
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
58
LeeSchuster
DukeEnergy
FRCC 3
DaleGoodwine
DukeEnergy
SERC
5
GregCecil
DukeEnergy
RFC
6
SelectedAnswer:
Yes
AnswerComment:
DukeEnergyrequestsfurtherclarificationonhowthedraftingteam
anticipatesanentitywillberequiredtodemonstratecompliancewithR5.
Aswritten,itdoesnotappearthattheproposedRequirementsand
Measuresareinalignment.Currently,therequirementsstatethatanentity
(TO,GO,LSE)mustconfirmthataFacilityiswithinaBalancingAuthority
Area’sMeteredBoundary,however,themeasuresuggeststhatanentity
shouldpointtoaproceduretodemonstratecompliancewithR5,R6,and
R7.WesuggestthatthedraftingteamrevisetheMeasurestobetteralign
withwhatisbeingaskedintherequirements,perhapsstatingthatan
attestationletterfromtheBAwouldbeadequatetodemonstrate
confirmationthatanentity’sFacilityiswithinaBAArea’sMetered
Boundary.
TheSDThasmodifiedFACͲ001toaddressyourconcerns.TheLSEhasbeen
removedfromthestandardbasedontheRBRinitiative.
Response:
AndreaBasinskiͲPugetSoundEnergy,Inc.Ͳ3Ͳ
SelectedAnswer:
No
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
59
AnswerComment:
Asworded,wedonotbelievethatBALͲ005Ͳ0.2bRequirementR1is
appropriateforFACͲ001Ͳ3.SinceFACͲ001Ͳ3appliestodocumentedFacility
interconnectionrequirements,itwouldbemoreappropriatetorequirethat
thedocumentedinterconnectionrequirementscontainlanguagestatingthat
transmission,generationandendͲuserinterconnectedFacilitiesmustbe
locatedwithintheBalancingAuthorityArea’smeteredboundaries.This
couldbeaccomplishedbyaddingR3.3stating“Proceduresforensuringthat
transmissionFacilities,generationFacilitiesandendͲuserFacilitiesarewithin
theBalancingAuthorityArea’smeteredboundaries.”Therequirementto
verifythatexistingfacilitiesarelocatedwiththemeteredboundariesofa
BalancingAuthorityAreaismostappropriatelyassignedtotheTOP,andnot
totheTO,GOandtheLSE.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
ResponsetoComments:
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
60
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
Response:
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
SelectedAnswer:
No
AnswerComment:
KCP&LbelievesmovingBALͲ005Ͳ02.bR1toFACͲ001shouldberejected;itis
anattempttoshoeͲhornRequirementsintoanunrelatedStandard,or,at
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
61
best,marginallyrelatedStandard.
TheFACͲ001Standardrelatestoentitiesseekingtointerconnectwiththe
BulkElectricSystem.TheProposedFACͲ001Ͳ3anditspredecessorversions’
Purposedeclarationstate,"Toavoidadverseimpactsonthereliabilityof
theBulkElectricSystem,TransmissionOwnersandapplicableGenerator
OwnersmustdocumentandmakeFacilityinterconnectionrequirements
availablesothatentitiesseekingtointerconnectwillhavethenecessary
information."
ItisunclearhowTransmissionOwners,GenerationOwners,andLoadͲ
ServingEntitiesconfirmingtheyarewithinaBalancingAuthority’smetered
boundariesrelatetoGeneratorOwnersseekinginterconnectionwiththe
BulkElectricSystem.TheFACͲ001Standardrelatestonewequipment
plannedtointerconnectwiththeBulkElectricSystemwhileBALͲ005Ͳ02.b
R1relatestocurrentandoperationalinterconnections.
Additionally,theSARdiscussesmovingtheTOP,LSE,andGOPfromBALͲ
005Ͳ02.b(SeeSAR,pp.4Ͳ5)totheFACStandards.Itisunclearwherethe
TOPdutiesunderR1landed.Itdidn’tlandinFACͲ001.Granted,theSARisa
frameworkandnotbinding,thelanguagesuggeststheSDTwasuncertain
whereto"put"theR1Requirement.However,theProposedFACͲ001Ͳ3R5
ViolationSeverityLevelstates,"TheTransmissionOperatorswith
TransmissionFacilitiesoperatinginanInterconnection…"Inconsideration
oftheVSLlanguageandtheproposedFACͲ001Ͳ3notexpresslyapplicable
toTransmissionOperators,KCP&LisconcernedthatmovingBALͲ005Ͳ02.b
R1toFACͲ001,createsanunstateddutyforTransmissionOperators.
Furthermore,theProposedFACͲ001Ͳ3Purposedeclarationisreiteratedin
ApplicabilitySec.4.1.2.1.,"GeneratorOwnerwithafullyexecuted
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
62
Agreementtoconductastudyonthereliabilityimpactofinterconnectinga
thirdpartyFacilitytotheGeneratorOwner’sexistingFacilitythatisusedto
interconnecttotheTransmissionsystem."
TheFACͲ001StandardrelatestonewinterconnectstotheBulkElectric
SystemandshouldnotbeusedasalandingpadforBALͲ005Requirements
thatnolongerarerelevanttoBALͲ005.KCP&Ldoesnotobjecttomoving
BALͲ005R1toanotherStandard,butFACͲ001isnottheappropriate
Standardandtheproposedchangesshouldbereconsidered.
Finally,intheeventthechangestoFACͲ001Ͳ3R5,R6,andR7areendorsed
bythestakeholders,KCP&LwouldasklanguagebeaddedtoFACͲ001Ͳ3to
highlightitisapplicabletonewfacilities,includingthefacilitiesidentifiedin
R5,R6,andR7.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
63
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
64
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
Yes
AnswerComment:
WeagreewithmovingBALͲ005Ͳ0.2bRequirementR1toFACͲ001
standard.However,giventhelikelyretirementoftheLSEfunctionalrole
considerationshouldbegivenintheSARtomakingthe
requirementapplicabletotheDPfunctionalentityrole.
ResponsetoComment:
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
65
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
Response:
LeePedowiczͲNortheastPowerCoordinatingCouncilͲ10ͲNPCC
GroupName:
NPCCͲͲProject2010Ͳ14.2.1Phase2ofBalAuthRelͲbasedControlsͲ
BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
GroupMemberName
Entity
Region Segments
AlanAdamson
NewYorkStateReliabilityCouncil,
NPCC 10
LLC
DavidBurke
OrangeandRocklandUtilitiesInc.
NPCC 3
GregCampoli
NewYorkIndependentSystem
NPCC 2
Operator
GerryDunbar
NortheastPowerCoordinating
NPCC 10
Council
MarkKenny
NortheastUtilities
NPCC 1
HelenLainis
IndependentElectricitySystem
NPCC 2
Operator
RobVance
NewBrunswickPowerCorporation NPCC 9
PaulMalozewski
HydroOneNetworksInc.
NPCC 1
BruceMetruck
NewYorkPowerAuthority
NPCC 6
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
DavidRamkalawan
BrianRobinson
WayneSipperly
EdwardBedder
MichaelJones
BrianShanahan
GlenSmith
RuiDaShu
66
NortheastPowerCoordinating
NPCC 10
Council
OntarioPowerGeneration,Inc.
NPCC 5
UtilityServices
NPCC 8
NewYorkPowerAuthority
NPCC 5
OrangeandRocklandUtilitiesInc.
NPCC 1
NationalGrid
NPCC 1
NationalGrid
NPCC 1
EntergyServices,Inc.
NPCC 5
NortheastPowerCoordinating
NPCC 10
Council
DominionResourcesServices,Inc.
NPCC 5
NortheastPowerCoordinating
NPCC 10
Council
NextEraEnergy,LLC
NPCC 5
TheUnitedIlluminatingCompany
NPCC 1
ISOͲNewEngland
NPCC 2
No
LoadServingEntity(LSE)function:NERCprovidedFERCwithjustificationto
retireBALͲ005Ͳ0.2bPartR1.3fortheLSEfunction(LSEfunction
deregistration).AddingLSErequirementstoFACͲ001doesnotappearto
alignwithNERC’sjustificationandtheintenttoretireBALͲ005Ͳ0.2bR1.3.
FACͲ001TableofComplianceElements:R5andR6referenceTransmission
OperatorandGenerationOperator,insteadofTransmissionOwnerand
GeneratorOwner.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
LeePedowicz
ConnieLowe
GuyZito
SilviaParadaMitchell
RobertPellegrini
KathleenGoodman
SelectedAnswer:
AnswerComment:
ResponsetoComment:
67
ThePurposeofFACͲ001isto“…makeFacilityinterconnectionrequirements
availablesothatentitiesseekingtointerconnectwillhavethenecessary
information.”AddingrequirementstoFACͲ001regardingmetered
boundariesappearstobemisplaced.Theproposedadditionsareongoing
requirementstoconfirmthemeteringoftransmissionfacilities.Theuseof
theword“confirm”isnotthesameastoestablishtheinterconnection
requirements.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
68
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
Response:
Likes:
1
HydroOneNetworks,Inc.,1,FarahbakhshPayam
Dislikes:
0
JasonSnodgrassͲGeorgiaTransmissionCorporationͲ1Ͳ
SelectedAnswer:
No
AnswerComment:
(1)FACͲ001Ͳ2wasrevisedin2013toeliminateanyrequirementsthatwere
notnecessaryforreliabilityaccordingtoFERCparagraph81directions.Asa
memberoftheFACͲ001Ͳ2SDTchargedwiththistask,GTCalongwiththe
othermembersfollowedthedirectivesofFERCandretainedonlythe
requirementsnecessaryforsystemreliability.Assuch14subͲrequirementsin
FACͲ001wereremovedincludingarequirementformeteringand
telecommunication.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
69
AlthoughGTCseesameritinensuringthattheAreaControlErroris
calculatedproperly,GTCbelievesthattheproposedrequirements(FACͲ001Ͳ
3ͲR5,R6andR7)doesnotresolveoraddressareliabilityconcernandwould
violateparagraph81criteria.
MoreoverGTCbelievethatrequirementsFACͲ001Ͳ3ͲR5,R6andR7address
specificneedsforoperatingthesystemandthereforebelongandalreadyare
includedinOperationsStandardssuchasTOPandIROandnotaPlanning
StandardassociatedwithFacilityinterconnectionRequirements.
(2)Aslistedwithinthisproject’sSAR,theProject2010Ͳ14.2BALStandards
PRT“believesthattherequirementstoidentifytheapplicableBAshould
perhapsbeintheinterconnectionagreements(viaFERC’sOATTorNAESB,
forexample),”webelievetheserequirementsalreadydo.Manyother
reliabilityrequirementsintheTOPandIROstandardssupportthe
identificationofInterconnectionFacilitiesthroughdatamodelingand
specifications.Forexample,TOPͲ003Ͳ3R4identifiesthat“eachBalancing
Authorityshalldistributeitsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoring.”TOPͲ003Ͳ3appliestothesameentitieslistedinthedraft
requirements.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
70
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
71
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
MikeONeilͲNextEraEnergyͲFloridaPowerandLightCo.Ͳ1Ͳ
SelectedAnswer:
No
AnswerComment:
WeappreciatetheworkbytheSDT,butdonotagreewithmovingBALͲ005Ͳ
0.2bRequirementR1toFACͲ001Ͳ3RequirementsR5,R6,andR7.Atthis
time,thewaytheBALͲ005requirementR1readsitposestobemoreofan
accountingissueversusareliabilityissue.Onealternativesolutionisto
removethelanguagefromthisstandard(FACͲ001Ͳ3)andincludeitinthe
ApplicationGuidelinessection.
ResponsetoComment:
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
72
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
73
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
PayamFarahbakhshͲHydroOneNetworks,Inc.Ͳ1Ͳ
SelectedAnswer:
No
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
GroupName:
ISOStandardsReviewCommittee
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
GroupMemberName
CharlesYeung
BenLi
MarkHolman
KathleenGoodman
GregCampoli
AliMiremadi
TerryBilke
ChristinaBigelow
SelectedAnswer:
AnswerComment:
ResponsetoComment:
74
Entity
Region Segments
SPP
SPP
2
IESO
NPCC 2
PJM
RFC
2
ISONE
NPCC 2
NYISO
NPCC 2
CAISO
WECC 2
MISO
RFC
2
ERCOT
TRE
2
No
TheSRCsupportsdeletingtheR1requirementsinBALͲ005Ͳ0.2b,and
recommendsplacingtheobligationinacertificationrequirement.
SeefileattachedtoQuestion1forthefulltextofthecommentsto
Question2
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
75
InFACͲ001Ͳ2R2,thewords“uponrequest”areusedinconjunctionwiththe
notificationrequirements.HowdoesaBAknowwhentorequestsuch
information?InFACͲ001Ͳ2R3,thereisnospecificmentionoftheBA.How
doestheTOknowwhenthenewloadwillaffectthereliabilityfunctionality
oftheBA,ormusttheTOnotifytheBAforeveryrequestfor
interconnection?ThenewrequirementswereintendedtoremovetheTOas
themiddlemanfortheserequirements.TOPͲ003Ͳ3includesthefollowing
words,“EachBalancingAuthorityshallretainevidenceforthreecalendar
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
76
yearsthatithasdistributeditsdataspecificationtoentitiesthathavedata
requiredbytheBalancingAuthority’sanalysisfunctionsandRealͲtime
monitoringinaccordancewithRequirementR4andMeasurementM4.”
HowistheBalancingAuthoritytoreceivetheknowledgethatnewload,
generationortransmissionisinterconnectingsothatitmaydistributeits
dataspecificationtoentitiesthathavedatarequiredbytheBalancing
Authority?ThisistheholeinthestandardsthatmodificationstoFACͲ001R3
andR4areintendedtofill.
Response:
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
Yes
ShawnaSpeerͲColoradoSpringsUtilitiesͲ1Ͳ
GroupName:
ColoradoSpringsUtilities
GroupMemberName
Entity
Region Segments
ShawnaSpeer
ColoradoSpringsUtilities
WECC 1
ShannonFair
ColoradoSpringsUtilities
WECC 6
CharlesMorgan
ColoradoSpringsUtilities
WECC 3
KalebBrimhall
ColoradoSpringsUtilities
WECC 5
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
77
SelectedAnswer:
No
TheFACͲ001standardisusedtofacilitateinterconnectionrequirementsfor
AnswerComment:
thoseentitiesseekinginterconnectionintotheBES.InthedraftFACͲ001Ͳ3
RequirementsR5ͲR7thelanguagespeakstothosewhoentitieswhoare
alreadyoperatinginaninterconnectionandthereforedoesnotfitthe
purposeofthisstandard.TheFACͲ001standardcannotbeusedtoenforce
R5–R7forthosefacilitiesthatalreadyexist.
TheLSEfunctionshouldnotbeincludedintheFACͲ001standardand
thereforeR7shouldberemovedinitsentiretyfromthedraft.InR7,itisnot
cleariftheLSE,TO,orGOwillberequiredtoaddressthisintheir
interconnectionrequirements.ThereisnorequirementforanLSEtohave
documentedfacilityinterconnectionrequirements.
ResponsetoComment:
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.TheLSEhasbeenremovedfromthestandardbased
ontheRBRinitiative.
AnswerComment:
ResponsetoComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
78
TotrulymakethisconsistentwiththepurposeoftheFACͲ001standardthe
wordingshouldberevisedtoaddressthedocumentedfacility
interconnectionrequirements.ThedraftstandardshouldrequirethattheTO
&ApplicableGOfacilityinterconnectionrequirementsaddressBAAmetered
boundsforthoseentitiesseekinginterconnection.Theentitiesseeking
interconnectionshoulddeterminetheiroperatingareaandthereforeBAA
meteredboundsfromtheirdesiredinterconnectionlocation.
CSUisoftheopinionthattheserequirementsbelongintheINTorTOPfamily
ofStandards.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
79
Response:
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
GroupName:
SPPStandardsReviewGroup
GroupMemberName
Entity
Region Segments
ShannonMickens
SouthwestPowerPool
SPP
2
JasonSmith
SouthwestPowerPool
SPP
2
AshleyStringer
OklahomaMunicipalPower
SPP
4
Authority
SelectedAnswer:
No
AnswerComment:
Theserequirementsdonotrisetothelevelofneedingacontinuously
auditedReliabilityStandard.Onceafacilityisinterconnectedandcertified,
thentheinclusionwithinaBA’smeteredboundsshouldbeverifiedatthat
time.Thereshouldnotbeaneedforcontinuingcertificationthatitremains
withinthemeteredbounds.Therequirementsasstatedonlyresultin
administrativeeffortsandareanexerciseinsubmittingattestations.
OnesuggestionwouldbetosimplyaddasubͲrequirementthatthe
TransmissionOwner’sInterconnectionRequirements(FACͲ001Ͳ3R1)must
includearequirementthatallinterconnectedfacilitiesmustbe
demonstratedtobewithinaBalancingAuthority’smetered
boundaries.Thentherewouldbenoneedforthenew,proposedR5Ͳ
R7.Thisputsthecomplianceeffortintoensuringthefacilityismetered
properlyuponinterconnection–tosatisfytheTOFacilityInterconnection
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
80
Requirements–ratherthananongoingverificationthatthefacilities
continuetobewithinthemeteredbounds.
ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothatthey
onlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
Response:
ErikaDootͲU.S.BureauofReclamationͲ5Ͳ
SelectedAnswer:
No
AnswerComment:
ReclamationrecommendsthatthedraftingteamproposetoretireBALͲ005Ͳ
0.2bR1insteadofmovingtherequirementintoFACͲ001Ͳ3.Reclamation
doesnotbelievethatthedraftingteamhasaddressedthePeriodicReview
Team’srecommendationtoidentify“whatisneededforensuringfacilities
arewithinaBalancingAuthorityAreapriortoMWbeinggeneratedor
consumed.”Liketheexistingrequirement,theproposedrequirementdoes
notmentionverifyingthatfacilitiesarewithinthemeteredboundariesofa
BalancingAuthorityArea“priortotransmissionoperation,
resourceoperation,orloadbeingserved.”Therefore,theproposed
requirementperpetuatesapaperworkburdenthatcostsstafftimeand
resourcesofGeneratorOperators,TransmissionOperators,andLoadServing
EntitieswithlongstandingarrangementswiththeirhostBalancing
Authority.RegisteredEntitiesacquiringletterstoconfirmthattheyareinthe
ResponsetoComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ResponsetoComment:
81
meteredboundariesofaBalancingAuthorityAreaprovidesnobenefitto
systemreliability.
RequirementR1fromtheVersion0BALͲ005standardwasoriginallyincluded
tomeetthegeneralrequirementforTieLineBiasControltobeeffective.In
theNERCGlossaryofTerms,ReportingACErequiresthat,“Allportionsofthe
Interconnectionareincludedinonearea[BAA]oranothersothatthesumof
allareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.”InitsVersion0form,R1wasdifficultorimpossibletoaudit.
Thenewversionofthestandardaddressesthisreliabilityconcernthrougha
modificationtothedefinitionofReportingACErequiringthatActualNet
InterchangeandScheduledNetInterchangeonlyincludeinterchangewith
otherBAAs.BymodifyingthedefinitionofReportingACEitbecomes
impossibletoexcludeanygenerator,transmission,orloadfromallBAAson
aninterconnectionbecauseexclusionfromoneBAAcanonlybe
accomplishedbytransferringthatgenerator,transmissionorloadtoan
adjacentBAA.Inaddition,inadvertentaccountingfromthenewBALͲ005Ͳ1
R7willrevealanyproblemsbetweenScheduledNetInterchangeas
comparedtoActualNetInterchangewithinaBAA.
Initsevaluationconsideringtheeliminationofthisrequirement,theSTD
realizedthatthereisnorequirementthattheBAbeinformedofthenew
facilitiestobeinterconnectedbeforetheactualinterconnectionwouldtake
place.ThisputstheBAintheunreasonablepositionofhavingtoadjustits
operationsfornewunknowngeneration,transmissionorloadwithout
advancednotice.TheintentoftheadditionstoR3andR4toFACͲ001isto
insurethattheBAreceivesadvancednoticeoftheinterconnection.Thisisa
oneͲtimerequirementsincethechangeinthedefinitionofReportingACE
addressedtheintentoftheoriginalBALͲ005Ͳ0R1andtheongoingreliability
issue.ThedraftingteamhasmodifiedtherequirementsinFACͲ001Ͳ3sothat
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
82
theyonlyapplytonewinterconnectingfacilitiesorfacilitymodificationsthat
wouldrequirematerialfacilitychanges,andthereforematerialchangesin
theloadtobebalanced.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
83
3.TheSDThasmovedtheBALͲ006Ͳ2RequirementR3intoBALͲ005Ͳ3sincethisrequirementdirectlyimpactsanentity’sabilityto
calculateanaccurateReportingACE.DoyouagreewithmovingthisrequirementintotheproposedBALͲ005Ͳ1standard?Ifnot,
pleaseexplaininthecommentareabelow.
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
SelectedAnswer:
Yes
AndrewPusztaiͲAmericanTransmissionCompany,LLCͲ1Ͳ
SelectedAnswer:
Yes
NickVtyurinͲManitobaHydroͲ1,3,5,6–MRO
SelectedAnswer:
Yes
ThomasFoltzͲAEPͲ5Ͳ
SelectedAnswer:
Yes
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
SelectedAnswer:
Yes
EmilyRousseauͲMROͲ1,2,3,4,5,6ͲMRO
GroupName:
MROͲNERCStandardsReviewForum(NSRF)
GroupMemberName
Entity
JoeDepoorter
MadisonGas&Electric
AmyCasucelli
XcelEnergy
ChuckLawrence
AmericanTransmissionCompany
ChuckWicklund
OtterTailPowerCompany
TheresaAllard
MinnkotaPowerCooperative,Inc
DaveRudolph
BasinElectricPowerCooperative
KayleighWilkerson
LincolnElectricSystem
JodiJenson
WesternAreaPower
Administration
LarryHeckert
AlliantEnergy
MahmoodSafi
OmahaPublicUtilityDistrict
ShannonWeaver
MidwestISOInc.
MikeBrytowski
GreatRiverEnergy
BradPerrett
MinnesotaPower
ScottNickels
RochesterPublicUtilities
TerryHarbour
MidAmericanEnergyCompany
TomBreene
WisconsinPublicService
Corporation
TonyEddleman
NebraskaPublicPowerDistrict
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
4
1,3,5,6
2
1,3,5,6
1,5
4
1,3,5,6
3,4,5,6
MRO 1,3,5
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
Segme
nts
3,4,5,6
1,3,5,6
1
1,3,5
1,3,5,6
1,3,5,6
1,3,5,6
1,6
Regio
n
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
84
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
85
SelectedAnswer:
No
AnswerComment:
MWHrmetersareforInadvertentInterchangeaccounting.Making
thischangewillconfusetheissueandwilladdunnecessary
obligations.AslongasthetwoBAsusecommonmetering,anyminor
errorinreportingACEiscontainedbetweenthemandhasnoimpact
ontheInterconnectionasawhole.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
SelectedAnswer:
No
AnswerComment:
MWHrmetersareforInadvertentInterchangeaccounting.Thereare
alreadyotherrequirementsproposedthatdealwithmakingsureACEis
realativelyaccurate.Additionally,aslongasadjacentBAsusecommon
metering,anyminorerrorinreportingACEiscontainedbetweenthem
andhasnoimpactontheInterconnectionasawhole.
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
86
87
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
Response:
AmyCasuscelliͲXcelEnergy,Inc.Ͳ1,3,5,6ͲMRO,WECC,SPP
SelectedAnswer:
No
AnswerComment:
MWHrmetersareforInadvententInterchangeaccounting.Makingthe
proposedchangecouldleadtoconfustionandunnecessary
obligations.IfthetwoBAsusecommonmetering,anyminorerrorin
ACEreportingiscontainedandwouldhavenoimpactonthe
Interconnectionasawhole.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
88
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio
n
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
Segme
nts
1
89
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
SouthernCompanyGeneration
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
WilliamShultz
SouthernCompanyGeneration
SelectedAnswer:
Yes
EleanorEwryͲPugetSoundEnergy,Inc.Ͳ1,3,5ͲWECC
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
BobSolomon
HoosierEnergyRuralElectric
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
BillHutchison
SouthernIllinoisPower
Cooperative
MichaelBrytowski
GreatRiverEnergy
EllenWatkins
SunflowerElectricPower
Corporation
JohnShaver
ArizonaElectricPower
Cooperative,Inc.
JohnCiza
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
6
1,3,5,6
1
1,3
1
Segme
nts
1
WECC 4,5
MRO
SPP
SERC
SERC
Regio
n
RFC
SERC 3
SERC 5
SERC
90
RyanStrom
ScottBrame
BillWatson
SelectedAnswer:
AnswerComment:
JohnShaver
SouthwestTransmission
WECC 1
Cooperative,Inc.
BuckeyePower,Inc.
RFC
4
NorthCarolinaElectric
SERC 3,4,5
MembershipCorporation
OldDominionElectricCooperative SERC 3,4
Yes
WeconcurwiththeSDT’srecommendation,asBALͲ005Ͳ1addresses
moreproactiveandrealͲtimeAGCoperationswhileBALͲ006addresses
moreafterͲtheͲfact.
Thankyouforyourcomments.
Response:
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
SelectedAnswer:
No
AnswerComment:
TexasREnoticedthereisnoredlineforBALͲ005Ͳ1.Redlinesarehelpful
inreviewingrevisions.
TexasREnoticedBALͲ006Ͳ2R3hasthephrase“withreadingsprovided
hourly”(emphasisadded)which,dictatesatimingaspect.BALͲ005Ͳ1
R1hasthephrase“todeterminehourlymegawattͲhourvalues”but
doesnothaveatimeaspectspecificallyrequired.TexasREinquires
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
91
92
whetherthiswastheintentoftheSDT(andTexasREisawareofthe
expectedhistoricalpracticeofhourlycommunicationsbetween
entities).
TheSDTelectednottoprovidearedͲlinesinceitwasnotmeaningful
andmoreconfusing.
TheOperatingProcesswilldeterminethetimeͲframefordistributionof
therequiredinformationbetweenadjacentBAAs.
Response:
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
SelectedAnswer:
Yes
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
SelectedAnswer:
No
AnswerComment:
AmerensupportsMISO'scommentsforthisquestion
PleaserefertotheresponsetotheMISOcomments.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
CarolChinnͲFloridaMunicipalPowerAgencyͲ4Ͳ
GroupName:
FMPA
GroupMemberName
Entity
Regio Segme
n
nts
TimBeyrle
CityofNewSmyrnaBeach
FRCC 4
JimHoward
LakelandElectric
FRCC 3
GregWoessner
KissimmeeUtilityAuthority
FRCC 3
LynneMila
CityofClewiston
FRCC 3
JavierCisneros
FortPierceUtilityAuthority
FRCC 4
RandyHahn
OcalaUtilityServices
FRCC 3
DonCuevas
BeachesEnergyServices
FRCC 1
StanRzad
KeysEnergyServices
FRCC 4
MattCulverhouse
CityofBartow
FRCC 3
TomReedy
FloridaMunicipalPowerPool
FRCC 6
StevenLancaster
BeachesEnergyServices
FRCC 3
MikeBlough
KissimmeeUtilityAuthority
FRCC 5
MarkBrown
CityofWinterPark
FRCC 3
MaceHunter
LakelandElectric
FRCC 3
SelectedAnswer:
No
AnswerComment:
FMPAagreesremovingR3fromBALͲ006,butitseemstohavecreated
duplicativerequirementsinBALͲ005.RequirementsR1andR8should
becombined.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
93
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
94
TheSDThasmodifiedtheproposedstandardtoaccommodateyour
recommendations.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
No
AnswerComment:
Thestandardstatesthatthepurposeisforacquiringdatatocalculate
ReportingACE.R1doesnotfallunderthatcategoryasitiscurrently
written.ItstatesitspurposeistodetermineMWhvalues.PJMsuggests
thefollowingchangetotheR1toalignwiththepurposeofBALͲ005:
R1.EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲ
Tie,andDynamicSchedulewithanAdjacentBalancingAuthorityis
equippedwithamutuallyagreedͲupontimesynchronizedcommon
source.todeterminehourlymegawattͲhourvalues.
WhilePJMagreesitisimportanttomaintainarequirementtocalculate
MWhvaluesforInadvertentInterchange,PJMsuggestthisbemovedto
aNAESBstandard.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
95
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ChantalMazzaͲHydroͲQu?becTransEnergieͲ2–NPCC
SelectedAnswer:
No
AnswerComment:
FortheQuebecInterconnection,itmakesmoresenseformetering
issuestobeinBALͲ006thanBALͲ005sinceasasingleBAasynchronous
Interconnection,NetInterchangesarenotcalculatedinour
ACE.HoweverHQunderstandsthatoursituationisexceptionalanddo
notopposethemoveofBALͲ006Ͳ2R3toBALͲ005Ͳ1.
Thankyouforyourcomment.
Response:
TheresaRakowskyͲPugetSoundEnergy,Inc.Ͳ1Ͳ
SelectedAnswer:
Yes
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio Segme
n
nts
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
96
DougHils
DukeEnergy
RFC
1
LeeSchuster
DukeEnergy
FRCC 3
DaleGoodwine
DukeEnergy
SERC 5
GregCecil
DukeEnergy
RFC
6
SelectedAnswer:
Yes
AnswerComment:
DukeEnergyagreeswiththemovetoBALͲ005Ͳ1,however,we
recommendthatthedraftingteamrevisetheMeasureforR1to
betteralignwithR1.1.ThesubͲrequirementR1.1statesthat
megawattͲhourvaluesmustbeexchangedbetweenAdjacent
BalancingAuthorities.TheMeasureprovidesguidanceforR1,but
doesnotprovideguidanceorexampleofdemonstratingcompliance
withR1.1.Moreinformationisneededtooutlinehowanentityis
expectedtodemonstratethattheexchangeofvaluestookplace,and
howoftenmusttheexchangetakeplace.
Thankyouforyourcomment.TheSDThasmademodificationstoboth
theproposedstandardandthemeasurements.
Response:
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,
3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
97
SelectedAnswer:
Yes
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
Yes
LeePedowiczͲNortheastPowerCoordinatingCouncilͲ10ͲNPCC
GroupName:
NPCCͲͲProject2010Ͳ14.2.1Phase2ofBalAuthRelͲbasedControls
ͲBALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
GroupMemberName
Entity
Regio Segme
n
nts
AlanAdamson
NewYorkStateReliabilityCouncil, NPCC 10
LLC
DavidBurke
OrangeandRocklandUtilitiesInc. NPCC 3
GregCampoli
NewYorkIndependentSystem
NPCC 2
Operator
GerryDunbar
NortheastPowerCoordinating
NPCC 10
Council
MarkKenny
NortheastUtilities
NPCC 1
HelenLainis
IndependentElectricitySystem
NPCC 2
Operator
RobVance
NewBrunswickPowerCorporation NPCC 9
PaulMalozewski
HydroOneNetworksInc.
NPCC 1
BruceMetruck
NewYorkPowerAuthority
NPCC 6
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
98
DavidRamkalawan
BrianRobinson
WayneSipperly
EdwardBedder
MichaelJones
BrianShanahan
GlenSmith
RuiDaShu
ConnieLowe
GuyZito
SilviaParadaMitchell
RobertPellegrini
KathleenGoodman
SelectedAnswer:
AnswerComment:
LeePedowicz
NortheastPowerCoordinating
NPCC 10
Council
OntarioPowerGeneration,Inc.
NPCC 5
UtilityServices
NPCC 8
NewYorkPowerAuthority
NPCC 5
OrangeandRocklandUtilitiesInc. NPCC 1
NationalGrid
NPCC 1
NationalGrid
NPCC 1
EntergyServices,Inc.
NPCC 5
NortheastPowerCoordinating
NPCC 10
Council
DominionResourcesServices,Inc. NPCC 5
NortheastPowerCoordinating
NPCC 10
Council
NextEraEnergy,LLC
NPCC 5
TheUnitedIlluminatingCompany NPCC 1
ISOͲNewEngland
NPCC 2
No
BALͲ006Ͳ2ͲͲ
R3.EachBalancingAuthorityshallensureallofitsBalancingAuthority
Areainterconnectionpointsareequippedwithcommon
megawattͲhourmeters,withreadingsprovidedhourlytothecontrol
centersofAdjacentBalancingAuthorities.
Istherearequirementforhourlyreporting?Whatismeantby
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
99
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
“common”?Isthisacertificationissue,oranInterconnection
Agreementissue,orastandard?
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
100
Response:
MikeONeilͲNextEraEnergyͲFloridaPowerandLightCo.Ͳ1Ͳ
SelectedAnswer:
Yes
PayamFarahbakhshͲHydroOneNetworks,Inc.Ͳ1Ͳ
SelectedAnswer:
No
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
GroupName:
ISOStandardsReviewCommittee
GroupMemberName
Entity
CharlesYeung
SPP
BenLi
IESO
MarkHolman
PJM
KathleenGoodman
ISONE
Regio
n
SPP
NPCC
RFC
NPCC
Segme
nts
2
2
2
2
101
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
GregCampoli
NYISO
NPCC 2
AliMiremadi
CAISO
WECC 2
TerryBilke
MISO
RFC
2
ChristinaBigelow
ERCOT
TRE
2
SelectedAnswer:
No
AnswerComment:
TheSRCopposestheproposaltomoveBALͲ006Ͳ2RequirementR3into
BALͲ005Ͳ3.
TheSRCrecommendsthatBALͲ006bedeleted.
SeefileattachedtoQuestion1forthefulltextofthecommentsto
Question3
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
102
Response:
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
Yes
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
103
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTie
LineBiasControlandtheaccuracyoftheperformancemeasuresbasedon
ReportingACE,i.e.CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemetered
toeachEMSfromthetielinemetersandagreedtobytheAdjacentBAAsis
requiredtobeavailableandmaybeintheOperatingProcesstoidentifyand
GroupName:
SPPStandardsReviewGroup
GroupMemberName
Entity
Regio Segme
n
nts
ShannonMickens
SouthwestPowerPool
SPP
2
JasonSmith
SouthwestPowerPool
SPP
2
AshleyStringer
OklahomaMunicipalPower
SPP
4
Authority
SelectedAnswer:
Yes
AnswerComment:
ThechangefromBALͲ006Ͳ2R3toBALͲ005Ͳ1R1andR8seemtobea
stepintherightdirection.Themeasureshowever(BALͲ005Ͳ1M1)
seemstoonlyrequireevidencethatacommonsourcewasagreed
upon,notthatthedatavalueswereactuallyexchangedbetween
AdjacentBA’sinatimelymanner.Iftheintentisonlytoensurea
commonsourcewasidentified,thenthatshouldbedoneincertification
anddoesnotrisetoaReliabilityStandard.
TheneedforcommonmegawattͲhourmetersbetweenBAsservesonly
toaccountforinadvertentinterchangebetweenthose
entities.AccumulatedinadvertentisnotrelatedtorealͲtime
reliability.ProposedBALͲ005Ͳ1R1shouldberemoved.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
104
Response:
105
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromthe
erroridentificationandmitigationprocess,theerrorsexcludedwillbealsobe
excludedfromtheperformancemeasurementsandresponsibilityfor
managingtheseexcludederrorswillbepassedtotheinterconnection.This
willresultinfrequencycontrolerrormanagedbyallBAAsthroughthe
frequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemetered
separatelywiththeMWhvaluesagreeduponbythetwoadjacent
BAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththe
MWhaccumulatedvaluestelemeteredseparatelyforeachtieline
eachhourforthefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲrates
betweenBAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferent
datacomparisonsforeachAdjacentBAAforeachtieline.Thesedata
comparisonsare:
mitigateerrorsaffectingtheaccuracyofscanͲratedatausedinthecalculation
ofReportingACEforeachBalancingAuthorityArea.Theseerrorsareusually
betweenintegratedhourlyscanͲratedataandhourlyaccumulatedmeterdata
butcanalsooccurasdifferencesbetweentheaccumulatedmeterdataoftwo
adjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ErikaDootͲU.S.BureauofReclamationͲ5Ͳ
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
106
AnswerComment:
none
AnswerComment:
107
Notwithstandingourcommentsonselectedrequirements
providedbelow,asanoverallcommentwedonotbelievesomeof
theproposedrequirementsbelongtoaReliabilityStandard.We
believeRequirementsR2,R4,R5andR6aremoresuitedfor
inclusionintheOrganizationCertificationRequirementfor
BalancingAuthoritiessincetheserequirementsstipulatethe
capabilitiesandfacilitiesthatneedtobeinplacetoenableaBAto
performitstasks.Theseare"oneͲoff"requirementsthatdonot
drivecontinuousbehaviors,andtheydonotrequirefrequent
updates.
TheserequirementshavebeenreviewedbythePeriodicReview
TeamandfoundtobenecessarytoremainasReliabilityStandard
requirements.TheDraftingTeamconcurs.
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
4.PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ005Ͳ1standardandaproposedsolution.
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
108
Inresponsetothecommentoflackofcontinuousbehaviorsand
infrequentupdatesnullifyingtheserequirements,theDrafting
TeamwouldaskwhatNERCproceduraldocumentisbeing
referencedtodeterminetheseasthresholdsforvalid
requirements.ManyNERCrequirementsoccurannuallyorupon
request.Additionally,theDraftingTeamdoesnotagreethatthese
are“oneͲoff”requirementsthatdonotneedtobecontinually
consideredintheoperationandmaintenanceofthesystemsused
tooperatethegrid.Forexample,flagginginaccuratedataand
establishingascanratemustbeconsideredeverytimenewdata
pointsareimplemented.
IftheBalancingAuthorityisnotrequiredtoconfirmtheaccuracyof
theirFrequencymeteringequipmentatsomereoccurring
periodicity,itwouldeventuallydeteriorateandimpacttheaccuracy
oftheReportingACE.
Similarly,ifthereisnotarequirementtoconfirmavailabilityofthe
systemcalculatingReportingACE,thereisnoconsequencefornot
maintainingsuchsystems.
b.RequirementR4:The99.95%uptimeisoverlyprescriptive
andtheredoesnotexistanytechnicaljustification.Unless
supportedbytechnicaljustification,thisrequirementshouldbe
removed.Furtheraddition,the0.001Hz“accuracy”requirement
ismisleading.Wesuggesttoreplace"accuracy"with"resolution"
tomoreproperlyconveytherequirement.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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109
c.RequirementR5:Weagreewiththeneedtoprovideoperating
personnelwithaccurateinformationthatsupportsawarenessand
calculationofReportableACE,buttheexampleslistedplacesemphasison
thesecondaryinformationasitfailstocapturethemoreimportantpiecesof
informationwhichwerelistedintheexistingBALͲ005.Wethereforesuggest
R5berevisedto:
R5.TheBalancingAuthorityshallmakeavailabletotheoperator
informationassociated
withReportingACEincluding,butnotlimitedto,realͲtimevaluesforACE,
Interconnection
frequency,NetActualInterchangewitheachAdjacentBalancingAuthority
Areaandqualityflagsindicatingmissingorinvaliddata.
TheSDTbelievessuchinformationisnecessaryfortheoperatortoknowatall
timesifitsReportingACEisaccurateandthereasonforwhyitmaynotbe
accurate,sincetheoperatorisutilizingReportingACEtobalanceDemandand
resourcesatalltimestoensureareliableInterconnection.
TheSDTbelieves“accuracy”and“resolution”conveysthesame
intent,however,theresponsesreceiveddidnotsupportchanging
theterm.
Withrespecttojustification,theSDTutilizedthesamevalues
currentlywithintheexistingBALͲ005standardandthebasevalue
theindustryutilizedwhenlistingspecificationsforEMS.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
110
d.R6:AswithourcommentsonR4,the99.5%uptimeisoverly
prescriptiveandrestrictive,andtheredoesnotexistanytechnical
justification.A99.5%uptimerequirementmeansthatallmodelbuildsand
softwareglitchescouldn’texceed43.8hoursinanygivenyear.Thisisoverly
restrictive.Unlesssupportedbytechnicaljustification,thisrequirement
shouldberemoved.
Withrespecttojustification,theSDTutilizedthesamevaluescurrentlywithin
theexistingBALͲ005standardandthebasevaluetheindustryutilizedwhen
listingspecificationsforEMS.
e.R7:Thisrequirementisnotneeded.R1alreadystipulatestheneedto
calculateandhourlymegawattͲhourvalues(andReportingACE,aswe
suggestedabove);andR4alreadystipulatesthescanrate.Failuretomeet
eitherrequirementwillresultinaBAbeingunabletocomplywiththe
standardinwhichcasetheBAmustdevelopcorrectiveactionstoreturnto
compliance.Havinganexplicitoperatingprocesstoidentifyandmitigate
errorsaffectingthescanͲrateaccuracyofdatausedinthecalculationof
ReportingACEisredundanttothecombinedrequirementsinR1andR4.We
thereforesuggesttoremoveR7.
TheSDThascombinedR1andR8tohelpunderstandtherequirements.In
addition,theSDThasprovidedadetailedrationalfortherequirements
includingR7“theOperatingProcess”.TheDraftingTeamagreesthatinthe
absenceofsignificantmetererror,R1andR4allowsforaccuratecontrolof
thegrid.Unfortunately,ifasignificantmetererrorexistsandgoes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
111
unaddressed,therecanbesignificantimpacttothecontrollingofthegrid
duringtheoperatinghournotcapturedinReportingACEthatisthenabsolved
throughtheaccountingprocessofreconcilingActualNetInterchange.Inthe
absenceofarequirementsuchasR7,thereisnoimpetusforanentityto
correctthemetererrorinatimelymannertoresolvetheproblem.
IfforwhateverreasonsR7isretained,thentheterm“OperatingProcess”
shouldnotbecapitalizedsinceitisnotaNERCdefinedterm.
TheOperatingProcesshasbeendefinedbyNERCas,’’Adocumentthat
identifiesgeneralstepsforachievingagenericoperatinggoal.AnOperating
Processincludesstepswithoptionsthatmaybeselecteddependingupon
RealͲtimeconditions.Aguidelineforcontrollinghighvoltageisanexampleof
anOperatingProcess.”
f.R8:Thisrequirementisimpliedinandredundantwith,R1.Suggestto
removeit.
TheSDThasreͲwrittenandcombinedR1andR8asthenewproposedR7and
hasprovidedclarifyingrationale.
I
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
BradPerrett
MikeBrytowski
ShannonWeaver
MahmoodSafi
LarryHeckert
JodiJenson
KayleighWilkerson
DaveRudolph
TheresaAllard
ChuckWicklund
ChuckLawrence
AmyCasucelli
JoeDepoorter
GroupMemberName
GroupName:
MinnesotaPower
GreatRiverEnergy
MidwestISOInc.
OmahaPublicUtilityDistrict
AlliantEnergy
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
1,5
1,3,5,6
2
1,3,5,6
4
1,6
1,3,5,6
1,3,5,6
1,3,5,6
1,3,5
1
1,3,5,6
3,4,5,6
Region Segments
WesternAreaPowerAdministration MRO
LincolnElectricSystem
BasinElectricPowerCooperative
MinnkotaPowerCooperative,Inc
OtterTailPowerCompany
AmericanTransmissionCompany
XcelEnergy
MadisonGas&Electric
Entity
MROͲNERCStandardsReviewForum(NSRF)
EmilyRousseauͲMROͲ1,2,3,4,5,6–MRO
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
112
TonyEddleman
TomBreene
TerryHarbour
ScottNickels
AnswerComment:
MRO
MRO
MRO
MRO
1,3,5
3,4,5,6
1,3,5,6
4
113
SeeattachmentwithStrikethrough
TheproposedR1shouldbeshortenedandmergedwithR7.Thereneednot
bementionof“mutuallyagreedupon”nor“timesychnronized”.AGCand
ACEuserealͲtimevalues,nothourlyvalues.
TheSDThasreͲwrittenandcombinedR1andR8asthenewproposedR7and
hasprovidedclarifyingrationale.
Thereisareliabilityneedfora“mutuallyagreedupon”sourceofthedata.
OtherwiseAdjacentBalancingAuthoritiescannotexpecttocontroltothe
samevaluesifthesourceofthosevalueshasnotbeenconfirmedtobe
common.Theconfirmationmayonlyneedtooccuronceorupon
modification.Butitimpactsthereliabilityofthedatabeingprovided.
BALͲ005Ͳ1
R1.EachBalancingAuthorityshallensurethathaveaprocesstooperateto
common,accurateeachTieͲLines,PseudoͲTies,andDynamicSchedules
withitsanAdjacentBalancingAuthorities.isequippedwithamutually
WisconsinPublicService
Corporation
NebraskaPublicPowerDistrict
MidAmericanEnergyCompany
RochesterPublicUtilities
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
114
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲratesbetween
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTieLineBias
ControlandtheaccuracyoftheperformancemeasuresbasedonReportingACE,i.e.
CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemeteredtoeachEMSfromthetie
linemetersandagreedtobytheAdjacentBAAsisrequiredtobeavailableandmay
beintheOperatingProcesstoidentifyandmitigateerrorsaffectingtheaccuracyof
scanͲratedatausedinthecalculationofReportingACEforeachBalancingAuthority
Area.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourly
accumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulated
meterdataoftwoadjacentBAAs.
agreedupontimesynchronizedcommonsourcetodeterminehourly
megawattͲhourvalues
Themeasureofthisrequirementisnotlogsorvoicerecordings.NSIis
alreadycheckedwithInadvertentAccountingandtheINTstandards.The
processthatwasproposedinR7couldbethevalidationandmeasureforR1
IfthechangetoR1aboveismade,R7isnolongernecessary.
R8isredundantwithwhencomparedtothesuggestedwordingabovefor
BALͲ005Ͳ1R1andBALͲ006R3.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
AnswerComment:
115
TheproposedR1shouldbeshortenedandmergedwithR7.Thereneednot
bementionof“mutuallyagreedupon”nor“timesychnronized”.AGCandACE
userealͲtimevalues,nothourlyvalues.
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromtheerror
identificationandmitigationprocess,theerrorsexcludedwillbealsobeexcluded
fromtheperformancemeasurementsandresponsibilityformanagingtheseexcluded
errorswillbepassedtotheinterconnection.Thiswillresultinfrequencycontrol
errormanagedbyallBAAsthroughthefrequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemeteredseparately
withtheMWhvaluesagreeduponbythetwoadjacentBAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththeMWh
accumulatedvaluestelemeteredseparatelyforeachtielineeachhourfor
thefirstBAA.
BAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferentdata
comparisonsforeachAdjacentBAAforeachtieline.Thesedatacomparisonsare:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
116
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTieLineBias
ControlandtheaccuracyoftheperformancemeasuresbasedonReportingACE,i.e.
CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemeteredtoeachEMSfromthetie
linemetersandagreedtobytheAdjacentBAAsisrequiredtobeavailableandmay
BALͲ005Ͳ1
R1.EachBalancingAuthorityshallhaveaprocesstooperatetocommon,
accurateTieͲLines,PseudoͲTies,andDynamicScheduleswithitsAdjacent
BalancingAuthorities.
TheSDTappreciatesthesuggestion.Unfortunately,thisproposed
requirementlanguagelacksspecificstowhatdata(hourlyversus
instantaneous)isbeingexchanged.
Themeasureofthisrequirementshouldnotbelogsorvoicerecordings.NSIis
alreadycheckedwithInadvertentAccountingandtheINTstandards.The
processthatwasproposedinR7couldbethevalidationandmeasureforR1
IfthechangetoR1aboveismade,R7isnolongernecessary.
R8isredundantwithwhencomparedtothesuggestedwordingabovefor
BALͲ005Ͳ1R1andBALͲ006R3
Thankyouforyourcomment.TheSDThasreͲwrittenandcombinedtheold
R1andoldR8intoanewproposedR7andthusanewmeasurehasbeen
created.However,theOperatingProcess(newproposedR6)shouldcontain
alloftheinformationusedtoidentifyandmitigateerrors.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
117
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromtheerror
identificationandmitigationprocess,theerrorsexcludedwillbealsobeexcluded
fromtheperformancemeasurementsandresponsibilityformanagingtheseexcluded
errorswillbepassedtotheinterconnection.Thiswillresultinfrequencycontrol
errormanagedbyallBAAsthroughthefrequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemeteredseparately
withtheMWhvaluesagreeduponbythetwoadjacentBAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththeMWh
accumulatedvaluestelemeteredseparatelyforeachtielineeachhourfor
thefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲratesbetween
BAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferentdata
comparisonsforeachAdjacentBAAforeachtieline.Thesedatacomparisonsare:
beintheOperatingProcesstoidentifyandmitigateerrorsaffectingtheaccuracyof
scanͲratedatausedinthecalculationofReportingACEforeachBalancingAuthority
Area.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourly
accumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulated
meterdataoftwoadjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
118
TheproposedR1shouldbeshortenedandmergedwithR7.Nomentionof
“mutuallyagreedupon”nor“timesychnronized”isnecessary.AGCandACE
userealͲtimevalues,nothourlyvalues.
Wesuggestthefollowing:
BALͲ005Ͳ1
R1.EachBalancingAuthorityshallhaveaprocesstooperatetocommon,
accurateTieͲLines,PseudoͲTies,andDynamicScheduleswithitsAdjacent
BalancingAuthorities.
TheSDTappreciatesthesuggestion.Unfortunately,thisproposed
requirementlanguagelacksspecificstowhatdata(hourlyversus
instantaneous)isbeingexchanged.
Themeasureofthisrequirementisnotlogsorvoicerecordings.NSIisalready
checkedwithInadvertentAccountingandtheINTstandards.Theprocessthat
wasproposedinR7couldbethevalidationandmeasureforR1.
R7wouldnotbenecessaryifthechangetoR1aboveismadeandR8wouldbe
redundantwithwhencomparedtothesuggestedwordingaboveforBALͲ005Ͳ
1R1andBALͲ006R3.
Thankyouforyourcomment.TheSDThasreͲwrittenandcombinedtheold
R1andoldR8intoanewproposedR7andthusanewmeasurehasbeen
created.However,theOperatingProcess(newproposedR6)shouldcontain
alloftheinformationusedtoidentifyandmitigateerrors.
AmyCasuscelliͲXcelEnergy,Inc.Ͳ1,3,5,6ͲMRO,WECC,SPP
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
119
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromtheerror
identificationandmitigationprocess,theerrorsexcludedwillbealsobeexcluded
fromtheperformancemeasurementsandresponsibilityformanagingtheseexcluded
errorswillbepassedtotheinterconnection.Thiswillresultinfrequencycontrol
errormanagedbyallBAAsthroughthefrequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemeteredseparately
withtheMWhvaluesagreeduponbythetwoadjacentBAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththeMWh
accumulatedvaluestelemeteredseparatelyforeachtielineeachhourfor
thefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲratesbetween
BAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferentdata
comparisonsforeachAdjacentBAAforeachtieline.Thesedatacomparisonsare:
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTieLineBias
ControlandtheaccuracyoftheperformancemeasuresbasedonReportingACE,i.e.
CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemeteredtoeachEMSfromthetie
linemetersandagreedtobytheAdjacentBAAsisrequiredtobeavailableandmay
beintheOperatingProcesstoidentifyandmitigateerrorsaffectingtheaccuracyof
scanͲratedatausedinthecalculationofReportingACEforeachBalancingAuthority
Area.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourly
accumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulated
meterdataoftwoadjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
ScottBrame
RyanStrom
JohnShaver
JohnShaver
EllenWatkins
MichaelBrytowski
BillHutchison
GingerMercier
BobSolomon
GroupMemberName
GroupName:
NorthCarolinaElectricMembership
Corporation
SunflowerElectricPower
Corporation
ArizonaElectricPowerCooperative,
Inc.
SouthwestTransmission
Cooperative,Inc.
BuckeyePower,Inc.
GreatRiverEnergy
SouthernIllinoisPowerCooperative
HoosierEnergyRuralElectric
Cooperative,Inc.
PrairiePower,Inc.
Entity
ACESStandardsCollaborators
SERC
RFC
WECC
WECC
SPP
MRO
SERC
SERC
RFC
3,4,5
4
1
4,5
1
1,3,5,6
1
1,3
1
120
Region Segments
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
BillWatson
AnswerComment:
SERC
3,4
121
1. WebelieveRequirementR1shouldfocusondetectionandcorrectionofa
problemratherthanaguaranteethatacommonsourceisavailable.This
wouldbetteralignwithariskͲbasedapproachthatNERCismandating
duringstandarddevelopment.Webelievethiscanbeachievedby
rephrasingtherequirementtoread
“EachBalancingAuthorityshallmonitormutuallyagreedͲupontimeͲ
synchronizedcommonsourcewithAdjacentBalancingAuthoritiesto
determinehourlymegawattͲhourvaluesforeachcommonTieͲ
Line,PseudoͲTie,andDynamicSchedule.”Wefeelthatbymovinginthis
direction,theassociatedVSLscanbesettomoreadjustablecriteria,such
asthelengthoftimebetweendetectionandcorrection,(e.g.under30,
60,and90days).
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainallofthe
informationusedtoidentifyandmitigateerrors.
2.WefeeltheSDTshouldaligntheVSLsforR2tomoreperformanceͲ
basedcriteria.WeagreethatsixͲsecondsisareasonablebenchmark,but
questionifitneedstobecategorizedasasevereVSL.Instead,we
recommendassigningaslidingtimescaletoeachVSL(e.g.greaterthanor
equalto6seconds,andgreaterthanorequalto12seconds,etc.)
Thankyouforyourcomment.TheSDThasmodifiedtherequirementto
provideadditionalclarity.
OldDominionElectricCooperative
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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122
2. InRequirementR3,theBAisexpectedtonotifyitsRCwithin45minutes
fromthebeginningofitsinabilitytocalculateReportingACE.IfaBA
encountersmultipleinstanceswhenitisunabletocalculateitsReporting
ACEinaconsecutiveminutetimeperiod,butneverhavesaninstancethat
isgreaterthanthirtyconsecutiveminutes,wewanttoconfirmthatthe
timeperiodfornotificationbeginswiththefirstreportableinstance.We
believethiscanbeaccomplishedbyreplacing“aninability”with“the
inability”atendoftherequirementtoread“…within45minutesofthe
beginningoftheinabilitytocalculateReportingACE.”
Thankyouforyourcomment.TheSDThasmodifiedtherequirementto
provideadditionalclarity.
4.WebelieveSystemOperatorsshouldbeidentifiedinRequirementR5,
asthisisaNERCͲdefinedGlossaryTerm.Moreover,itdoesnotprovide
anyambiguityforauditorsandbetteralignswiththosepersonnel
identifiedtocompletetrainingforreliabilityͲrelatedtasksinReliability
StandardPERͲ005Ͳ2.
TheSDTthanksyouforyourcomment.However,theSDTbelievesthat
thetermSystemOperatoristoobroadandmaynotaddressthecorrect
personnel.Byusingthetermoperator,theBAwillassuretheinformation
isprovidedtothecorrectpersonnel.
5.ForRequirementR5,weagreewiththeSDT’sapproachthatReporting
ACEcanbeaprimarymetrictodetermineoperatingactionsor
instructions.Furthermore,SystemOperatorsshouldbeawareofwhen
suchmetricsarebasedonpoororinsufficientdata.However,we
disagreewiththeSDT’sapproachtakeninthewordingofthis
requirement.Proofoftheexistenceofagraphicaldisplayordatedalarm
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
123
log,asmentionedaspossibleevidenceforcompliance,willonlyleadto
confusiononhowevidenceshouldbepresented.Webelieverewording
thisrequirementto“eachBalancingAuthorityshallmonitorthequalityof
informationusedtocalculateitsownReportingACE”achievestheintent
of“makingavailable”sufficientdatatoSystemOperators.
TheDraftingTeamdisagreesthatlanguagetodirectthe“monitoring”of
datawillresultininvaliddatabeingbroughttotheattentionofan
operator.Effectivemonitoringcanonlyoccurifoneknowswhat
representsinvaliddata,providedinthisinstancebytheflagging.The
purposeofthemeasurementistodemonstratethatifadequateflagging
ofinvaliddataexists,itwouldlikelyappearonanalarmlogorgraphical
display.
6.WefeeltheSDTshouldproviderationaleontheneedforRequirement
R6.Whileweagreethat“ReportingACEisanessentialmeasurementof
theBA’scontributiontothereliabilityoftheInterconnection,”webelieve
arequirementmeasuringtheavailabilityofaReportingACEcalculation
systemisunnecessary.SystemOperators,whenindistress,likelywillrely
onfrequencymetermeasurementsandcommunicationswithother
AdjacentBAswhenReportingACEisnotavailable.Thisproposed
standardalreadyhasanavailabilityrequirementlistedinRequirementR4,
andwitharequirementthathasahigheravailabilityrate.Webelieve
requiringasystembeavailableshouldbereservedfortheEROEvent
AnalysisProcess,muchlikeSCADAisforRCsandTOPs.
ReportingACEisanessentialmeasurementoftheBA’scontributionto
thereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthat
ReportingACEbesufficientlyavailabletoassurereliability.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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124
7.WebelievetheVSLscriteriaforRequirementR7couldbemore
performanceͲbased,particularlywithhowfasttheBAtooktomitigate
errorsaffectingthescanͲrateaccuracyofdata.Werecommendsliding
scalecriteria,suchaswithin15minutes,within30minutes,etc.
Unfortunatelysincetheresolutionofeachmetererrorsituationisunique
dependingonthesizeoftheerror,thecriticalityofthemeter,the
equipmentavailability,andmeterlocation,theDraftingTeamcouldnot
usetimingasdeterminant.Sincehavingaprocessisatrueorfalse
condition,itleftonlyoneVSLlevel.
8.InRequirementR8,webelievetherequirementshouldfocuson
detectionandcorrectiontobetteralignwithariskͲbasedapproach.We
believethiscanbeachievedbyrephrasingtherequirementtoread“Each
BalancingAuthorityshalluseacommonsourceforTieͲLines,PseudoͲTies,
andDynamicScheduleswithAdjacentBalancingAuthoritieswhen
calculatingReportingACE.”Wefeelthatbymovingtherequirementin
thisdirection,theassociatedVSLscanbesettoadjustablecriteria,suchas
thelengthoftimebetweendetectionandcorrection,i.e.under15
minutes,under30minutes,etc.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainallofthe
informationusedtoidentifyandmitigateerrors.
9.Thedataretentionoftheproposedstandard,currentyearplusthree
years,issignificantlylargerthantheoneyearretentionfoundinthe
currentstandardandgoesbeyondthethreeͲyearauditcycleforBAs.In
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
125
ThecurrenteffectiveversionofBALͲ003Ͳ1requiresBalancingAuthorities
toretaincurrentyear,plusthreecalendaryearsofReportingACEdata.
10.WebelievetheImplementationPlanshouldbeupdatedtoaccountfor
theretirementofIROͲ005Ͳ3.1a,asRequirementR1.6ofthatstandardhas
theRCmonitoringACEandnotReportableACEforallitsBAs.
TheRCspecifiestheinformationtobesuppliedbytheBAs.
11.ThethirdbulletoftheproposeddefinitionforAutomaticTimeError
Correction,aslistedwithintheImplementationPlan,hasatypographical
errorandshouldreferenceε10.
Thankyou.Wewillmakethatcorrection.
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
thecontextofaRiskͲBasedCMEP,wefeelanentityshouldonlyneedto
retainoneyear’sworthofdata.Thereisminimalreliabilitybenefitto
requiringanentitytostoredataforlongerthanoneyear,especially
consideringthetoolsinplacefortheEROtospotcheckorselfͲcertify
complianceactivitiesmorefrequentlythananaudit.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
126
ReportingACEhasbeenredefinedtorequirethatallDCasynchronoustie
lineswithotherinterconnectionsberepresentedasSourceͲSinkpairsand
excludedfromReportingACE.Thedraftingteamdidthistoinsurethaterrors
resultingfromtiestootherinterconnectionswouldnotaffectthequalityof
TieLineBiascontrol.ThecontributionofDCflowsfromother
interconnectionsisalreadyincludedintheinterconnectionfrequency,and
therefore,thereshouldbenoadjustmentforDCtieflowsorDCschedulesin
ReportingACEforsingleBAinterconnections.
ReportingACEforasingleBAinterconnectionisdefinedas:
RACE=(NIA–NIS)–10B(FA–FS)+IME
1. AsstatedintheanswertoQuestion1,TexasREisconcernedtheSDT
hasnotconsideredinterconnectionswithasingleBA.TheinitialSAR
commentsincludedthefollowingstatement:“WithinthePurpose
statementorApplicabilitysection,thePRTalsorecommendsthatthe
SDTconsideraddressingtheHydroQuebecexceptionfortielinebias
controlinsomeform,orasingleͲBAexception.“Itdoesnotappear
theSDTaddressedthesingleͲBAissuewhichresultsintheReliability
StandardnotbeingapplicabletotheERCOTandQuebec
Interconnections.This,inturn,affectsBALͲ001applicability.If
ReportingACEisnotapplicabletointerconnectionswithasingleBA,
BALͲ001mightnotapplytotheERCOTandQuebecInterconnections.
Additionally,anyBAthatconnectswiththeERCOTInterconnectionBA
willnotbeabletoaccuratelydetermineReportingACEwhichcould
causefailureofBALͲ001forthoseBAs(assumingtheyutilizenet
interchangevaluesintheirReportingACE).Thisomissioncreatesa
reliabilitygap.TexasRErecommendsincludingInterconnectionswitha
singleBA.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
127
3. AsynchronousTiesshouldbeincludedinthederivationofACEwhere
applicable.Withoutit,ReportingACEwillbeoffbythemagnitude
ItistheintentoftheDraftingTeamtoaddormodifyalltermslisted
underthe“NeworModifiedTerms”section.
2.
Thereseemstobesomeinconsistencywithregardstodefinitions.For
example,thedefinitionof“ReportingACE”intheStandardisdifferent
thantheNERCGlossaryofTerms(Glossary)butthereisno
redline.Thedefinitionof“AGC”isdifferentfromtheGlossaryand
thereisaredline.IsintentoftheSDTtochangebothtermsinthe
Glossary?FrequencyBiasSettingisnotdefinedwithinthisStandardso
itappearsthereisnochangetothatterm.
CPS1={2–[(RACE/Ͳ10B)x(FA–FS)]/H12}x100={2Ͳ[(FA–FS)2/H12]}x100
ThusfinalcomplianceisnotdependentupontheFrequencyBiasTerm.The
sameistrueforBAAL.
SincetherearenotielinesanotherBAonthesameinterconnection,thefirst
term,(NIA–NIS),becomeszero.SincetherearenotielinestoanotherBAon
thesameinterconnection,thethirdtermalsobecomeszero.Theleavesthe
ReportingACEfortheBAas:
RACE=–10B(FA–FS)
ThisReportingACEisusedintheCPS1andBAALrequirementsandmustbe
calculatedtodeterminecompliancewiththoserequirementsalthoughthe
actualvalueofReportingACEisnotusedbecauseitisoffsetbyotherpartsof
therequirements.Forexample,inCPS1:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
128
frequencyapplicabletotheflowsacrossaDCtie(especiallyifatripof
theDCoccursoranerrorinscheduling).
InthedefinitionofReportingACEasynchronousDCtiesbetween
InterconnectionsareexcludedfromReportingACEandarehandledas
eitherageneratororload.
4.
TexasREnoticedtheterm“adjacent”isnotcapitalizedinM1.Texas
RErecommendsremoving“its”whendescribing“AdjacentBalancing
Authority”astherecouldbemorethanoneAdjacentBalancing
AuthorityinM1.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.
TomakeR5consistentwiththePurposestatement,TexasRE
recommendschanging“operator”toSystemOperatortobeclearon
which“operator”theinformationshallbemadeavailable.Thischange
shouldalsotakeplaceintheVSLforR5.
TheSDTthanksyouforyourcomment.However,theSDTbelieves
thatthetermSystemOperatoristoobroadandmaynotaddressthe
correctpersonnel.Byusingthetermoperator,theBAwillassurethe
informationisprovidedtothecorrectpersonnel.
5.
PerthecommentinQuestion1,R7shouldbeforallBAsnotjustBAs
“withinamultipleBalancingAuthorityInterconnection”.R7should
onlyberelevanttotheareaoftheBalancingAuthoritythatis
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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129
7. TexasREnoticedtheVSLlanguageforR3doesnotinclude“for30
consecutiveminutes”.Shouldtherebeadashin“30Ͳconsecutive”in
Requirement3?
Thankyouforyourcomment.TheSDThasmodifiedthestandardto
addressyourconcerns.
8.
TexasRErecommendschangingtheverbiagefrom“eachcalendar
year”to“annually”orfor“eachrolling12monthperiod”.Specifically,
R4andR6includetheterm“calendaryear”whichimpliesJan1toDec
31.Therefore,ifaCEAevaluatescompliancetotheRequirementin
midͲyear,therecannotbeanassertionofcomplianceforthecurrent
year.Consequently,iftheCEAreturnsintwoyears,thehalfyear’s
periodofdatashouldbeavailabletoascertaincompliance(perthe
implementinganOperatingProcess.
TheintentoftherequirementisapplicableonlytoBAAsoperatingina
multipleBAAInterconnection.
6. TexasREnoticedtheVSLforR1doesnotincludelanguageshould
includelanguageforeachTieLine,PseudoͲTieorDynamicScheduleto
beequippedwithanagreeduponsourcetodeterminevalues.Asis,
theVSLignoresthe“equipped”languagewithintheStandard.
Thekeyelementsoftherequirementaretheagreementofasource
providinghourlyvalues,whichareaddressedintheVSL.TheDrafting
TeamdoesnotbelievetheVSLlanguageisunclearnothavingrestated
theword“equipped”.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
Response:
AnswerComment:
AmerensupportsMISO'scommentsforthisquestion
CarolChinnͲFloridaMunicipalPowerAgencyͲ4Ͳ
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
130
EvidenceRetentionstatements.TexasREwouldliketheSDTconsider
whetherthisviolatestheRoPAppendix4CSection3.1.4.2Period
Covered“TheauditperiodwillnotbeginpriortotheEndDateofthe
previousComplianceAudit.”?Morever,doesitcauseagapin
compliancemonitoring(andreflectapossiblegapinreliability)?
SinceanAuditPeriodwillincludeatleastoneentirecalendaryear,the
DraftingTeamfeels“calendaryear”isasufficienttimeframe.Data
Retentionrequirementsinastandardcanandoftendodifferfromthe
AuditPeriod.Thisisforvariousreasons,ofteninvolvingthemagnitude
ofdatathatmayneedtoberetained.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
MaceHunter
MarkBrown
MikeBlough
StevenLancaster
TomReedy
MattCulverhouse
StanRzad
DonCuevas
RandyHahn
JavierCisneros
LynneMila
GregWoessner
JimHoward
TimBeyrle
GroupMemberName
GroupName:
FMPA
LakelandElectric
CityofWinterPark
KissimmeeUtilityAuthority
BeachesEnergyServices
FloridaMunicipalPowerPool
CityofBartow
KeysEnergyServices
BeachesEnergyServices
OcalaUtilityServices
FortPierceUtilityAuthority
CityofClewiston
KissimmeeUtilityAuthority
LakelandElectric
CityofNewSmyrnaBeach
Entity
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
FRCC
3
3
5
3
6
3
4
1
3
4
3
3
3
4
Region Segments
131
Response:
AnswerComment:
132
FMPAdisagreeswiththeuseoftheterm“accuracy”inR4.2.Webelievethe
intentwouldbebetterdescribedbytheterm“precision”,orperhaps“degree
ofaccuracy”.
TheSDTbelieves“accuracy”and“precision”conveysthesameintent,
however,theresponsesreceiveddidnotsupportchangingtheterm.
FMPAdoesnotfindanytechnicaljustificationforthe99.5%availability
requirementinR6,andbelievesitmaybeduplicativewithBALͲ001and
presentadoublejeopardyissue.
Withrespecttojustification,theSDTutilizedthesamevaluescurrentlywithin
theexistingBALͲ005standardandthebasevaluetheindustryutilizedwhen
listingspecificationsforEMS.
TheavailabilityofReportingACEisnotduplicativeoftherequirementsinBALͲ
001.BALͲ001requiresacertainlevelofperformance.Thatperformanceis
calculatedbasedonvaliddata.Anyinvaliddata,suchasunavailable
ReportingACEistobeexcludedinitsmeasurement.Thereforenodouble
jeopardyexists.
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
AnswerComment:
133
ProposedStandard:
LocatedinBALͲ005Ͳ1R1:
R1.EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,and
DynamicSchedulewithanAdjacentBalancingAuthorityisequippedwitha
mutuallyagreedͲupontimesynchronizedcommonsourcetodetermine
hourlymegawattͲhourvalues.
1.1.ThesevaluesshallbeexchangedbetweenAdjacentBalancingAuthorities.
Thephrase“TieͲLine”isnotlistedintheNERCGlossary,butinstead“TieLine”
islisted.
Definition:
oTieLine:
•AcircuitconnectingtwoBalancingAuthorityAreas.
Thankyou.Thatcorrectionwillbemade.
Thedefinitionof“PseudoͲTie”shouldbeupdatedtoincludeReportingACEif
thatisthepurposeoftheBALͲ005Ͳ1R1.
Definition:
oPseudoͲTie:
•AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeand
includedintheActualNetInterchangeterm(NIA)inthesamemannerasaTie
LineintheaffectedBalancingAuthorities’controlACEequations(oralternate
controlprocesses).
Thankyou.WewillupdatethedefinitiontoreferenceReportingACE.
IftheSDTchoosesnottochangethelanguageforR1,thelanguageinR1.1
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
AnswerComment:
134
•IntheMappingDocumentforBALͲ005Ͳ1,R9,thereappearstobea
contradictionintheDescriptionandChangeJustificationsectionaboutthe
HVDClinksandtheirinclusionornotinReportingACEcalculationvsthe
ChantalMazzaͲHydroͲQu?becTransEnergieͲ2ͲNPCC
shouldbemodified.WiththecurrentlangaugethepurposeofR1.1isto
exchangethehourlymegawattͲhourvalueswiththeappropriateBalancing
AuthoritytodeterminebillingandInadvertentInterchange.Thisshouldbe
statedmoreclearlyasthecurrentrequirementhasitwrittenthatthevalues
aresharedwith[any]AdjacentBalancingAuthority.
PJMproposesthefollowingR1.1:
1.1.ThesevaluesshallbeexchangedforeachTieLine,PseudoͲTie,and
DynamicSchedulesharedbetweenaffectedBalancingAuthorities.
TheSDTsintentwiththeoldRequirementR1istoensurethattheinformation
isavailabletotheBAsforuseinthecalculationofReportingACE.TheSDThas
reͲwrittenandcombinedtheoldR1andoldR8intoanewproposedR7and
thusanewmeasurehasbeencreated.However,theOperatingProcess(new
proposedR6)shouldcontainalloftheinformationusedtoidentifyand
mitigateerrors.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
135
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTieLineBias
ControlandtheaccuracyoftheperformancemeasuresbasedonReportingACE,i.e.
CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemeteredtoeachEMSfromthetie
linemetersandagreedtobytheAdjacentBAAsisrequiredtobeavailableandmay
beintheOperatingProcesstoidentifyandmitigateerrorsaffectingtheaccuracyof
definitionsofScheduledandActualNetInterchangesthatexclude
asynchronousDCtieͲlinesdirectlyconnectedtoanotherinterconnection.
•R1vsR8:HQfailatoseethedifferencebetweenthe2
requirements.PerhapstheRationalesshouldbeenhancedforabetter
understanding.
•M1andM8donotseemappropriatemeasuresforanagreementon
commonmeteringorothersources.HQsuggesstfavoringawritten
agreementratherthanoperatorlogsorvoicerecordings.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
•EventhoughHQagreesthatbalancingauthoritiesshouldusecommon
meteringequipment,wefeelthatR1doesnotbelonginBALͲ005.This
requirementrelatestoenergymeasurementsthatareusedforaccounting
purposesandthatdonotcomeintoplayinreportingACEcalculation.This
requirementshouldremaininBALͲ006anddoesnotaffectinany
wayautomaticgenerationcontrol.R8doesaddressperfectlythecommon
meteringneedsbetweenbalancingauthoritiesforrealͲtimecontrol.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
TheresaRakowskyͲPugetSoundEnergy,Inc.Ͳ1Ͳ
136
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromtheerror
identificationandmitigationprocess,theerrorsexcludedwillbealsobeexcluded
fromtheperformancemeasurementsandresponsibilityformanagingtheseexcluded
errorswillbepassedtotheinterconnection.Thiswillresultinfrequencycontrol
errormanagedbyallBAAsthroughthefrequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemeteredseparately
withtheMWhvaluesagreeduponbythetwoadjacentBAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththeMWh
accumulatedvaluestelemeteredseparatelyforeachtielineeachhourfor
thefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲratesbetween
BAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferentdata
comparisonsforeachAdjacentBAAforeachtieline.Thesedatacomparisonsare:
scanͲratedatausedinthecalculationofReportingACEforeachBalancingAuthority
Area.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourly
accumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulated
meterdataoftwoadjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
AnswerComment:
DaleGoodwine
LeeSchuster
DougHils
GroupMemberName
GroupName:
DukeEnergy
DukeEnergy
DukeEnergy
DukeEnergy
Entity
SERC
FRCC
RFC
5
3
1
Region Segments
137
ForBALͲ005,R8,“MWFlowValues”shouldbespecificallymentionedinR8
andnotjustintheR8Rationale.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
GregCecil
AnswerComment:
RFC
6
138
Generalcomment:DukeEnergyrecommendsthedraftingteamconsider
movingtheproposedR8toR2.Wefeelthatbasedonthecommonsubject
matterofbothoftheserequirements,thatitwouldbemoreappropriateto
havethemconsecutivelylistedwithinastandard.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
R4:DukeEnergyrequestsfurtherclarificationregardingonhowanentity
maydemonstratecompliancewithR4.2specifically.Also,morebackground
informationregardingwherethe0.001Hznumbercamefromandwhatitis
measureagainstwouldaddtoclarityofthestandard.PerhapsanOperating
Guidelinethatprovidesguidanceorexamplesonhowanentitymay
demonstratecompliance,aswellasabackgroundonthe0.001Hznumber.
Calibrationtestingcanbeperformedandresultsprovidedasevidence.The
measurementistakendirectlyfromtheexistingR17ofBALͲ005Ͳ0.2b.The
SDTwillpresentyoursuggestiontotheNERCOCforconsideration.
R5:WerequestfurtherclarificationontheuseofthetermoperatorinR5.Is
thisinreferencetoaSystemOperator,ifso,werecommendstatingsointhe
standard.Aswritten,itappearsthatthestandardisinconflictwiththe
rationaleforR5whichusesthetermSystemoperator.
DukeEnergy
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
AnswerComment:
139
Asworded,wedonotbelievethatBALͲ005Ͳ0.2bRequirementR1is
appropriateforFACͲ001Ͳ3.SinceFACͲ001Ͳ3appliestodocumentedFacility
interconnectionrequirements,itwouldbemoreappropriatetorequirethat
thedocumentedinterconnectionrequirementscontainlanguagestatingthat
transmission,generationandendͲuserinterconnectedFacilitiesmustbe
locatedwithintheBalancingAuthorityArea’smeteredboundaries.Thiscould
beaccomplishedbyaddingR3.3stating“Proceduresforensuringthat
transmissionFacilities,generationFacilitiesandendͲuserFacilitiesarewithin
theBalancingAuthorityArea’smeteredboundaries.”Therequirementto
verifythatexistingfacilitiesarelocatedwiththemeteredboundariesofa
BalancingAuthorityAreaismostappropriatelyassignedtotheTOP,andnot
totheTO,GOandtheLSE.
IfaTransmissionOwnerwasrequiredtostateintheirInterconnection
requirementsthattransmission,generation,andloadmustbewithinthe
meteredboundaryofaBAA,itwouldputtheonerousontheTransmission
AndreaBasinskiͲPugetSoundEnergy,Inc.Ͳ3Ͳ
TheSDTthanksyouforyourcomment.However,theSDTbelievesthatthe
termSystemOperatoristoobroadandmaynotaddressthecorrect
personnel.Byusingthetermoperator,theBAwillassuretheinformationis
providedtothecorrectpersonnel.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
Response:
AnswerComment:
140
KCP&LincorporatesbyreferenceitsresponsetoSurveyQuestionNo.2.
LeePedowiczͲNortheastPowerCoordinatingCouncilͲ10ͲNPCC
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
Ownertoenforceit.Thereliabilityconcernoftheseelementsnotbeing
withinaBAAisaNERCreliabilityconcernandmustbeenforceablebyNERC.
ItisnotappropriateforaTOPtoberesponsibletoarrangefortheBalancing
Authorityarrangementsforload,generation,andtransmissionfacilitiesthat
theymaynotown.Theyhaveneithertheauthoritynorobligation.Thatis
whytheapplicabilityisplacedontheownersandnottheoperators.TheLSE
hasbeenremovedfromthestandardbasedontheRBRinitiative.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
WayneSipperly
BrianRobinson
DavidRamkalawan
LeePedowicz
BruceMetruck
PaulMalozewski
RobVance
HelenLainis
MarkKenny
GerryDunbar
GregCampoli
DavidBurke
AlanAdamson
GroupMemberName
GroupName:
NewYorkPowerAuthority
UtilityServices
NortheastPowerCoordinating
Council
OntarioPowerGeneration,Inc.
NewYorkPowerAuthority
HydroOneNetworksInc.
IndependentElectricitySystem
Operator
NewBrunswickPowerCorporation
NewYorkIndependentSystem
Operator
NortheastPowerCoordinating
Council
NortheastUtilities
NewYorkStateReliabilityCouncil,
LLC
OrangeandRocklandUtilitiesInc.
Entity
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
5
8
5
10
6
1
9
2
1
10
2
3
10
Region Segments
NPCCͲͲProject2010Ͳ14.2.1Phase2ofBalAuthRelͲbasedControlsͲ
BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
141
KathleenGoodman
RobertPellegrini
SilviaParadaMitchell
GuyZito
ConnieLowe
RuiDaShu
GlenSmith
BrianShanahan
MichaelJones
EdwardBedder
AnswerComment:
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
2
1
5
10
5
10
5
1
1
1
142
IntheAutomaticGenerationControl(AGC)definitionconsiderremoving
“Automaticallyadjusts”andreplaceitwith“determines”.TheBAdoesnot
alwayshavethecapabilityofmakinganautomaticadjustment.Forexample,
aBAcansendarequestedloadingvaluedownthroughtheRIG(Remote
IntelligentGateway)andhavethelocalGO/GOPorDP/LSEwithsmallerunits
tomeettheload,butdonothavedirectcontrolovertheunits.It’sthelocal
GO/GOPorDP/LSEwhoownsand/oroperatestheunitsthatactuallyexecute
changesinloading.
ISOͲNewEngland
TheUnitedIlluminatingCompany
NortheastPowerCoordinating
Council
NextEraEnergy,LLC
NortheastPowerCoordinating
Council
DominionResourcesServices,Inc.
EntergyServices,Inc.
NationalGrid
NationalGrid
OrangeandRocklandUtilitiesInc.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
143
ThescanͲrateaccuracyofReportingACEiscriticaltotheeffectivenessofTieLineBias
TheSDThasmodifiedthedefinitiontoaddressyourconcern.TheLSEhas
beenremovedfromthestandardbasedontheRBRinitiative.
RequirementR1
Theuseofthefollowingtextneedstobereconsidered:
…eachTieͲLine,PseudoͲTie,andDynamicSchedulewithanAdjacentBA…
…timeͲsynchronizedcommonsource…
…todeterminehourlymegawattͲhourvalues
PseudoͲtiesandDynamicSchedulesarenottielines;theyareoutputvalues
fromresources.Insomecasestheseoutputvaluescanbeuseddirectly,butin
othercasesthevaluesareadjustedbytheEMStorepresenttheproportionof
theoutputtobeincorporatedintotheBAsACE.
TheDraftingTeamsisnotcertainifthereisaquestionorcommentbeing
statedhere.
Thephrase“timeͲsynchronizedcommonsource”requiresexplanation.Iftwo
BAsareusingacommonsourceforrealtimeflows,thenbydefinitionthe
valuesaresynchronized.If,ontheotherhand,R1onlyappliestoHourly
(Billing)valuesthephraseisstillsuperfluous.However,ifthephraseismeant
tomandatethatallinterͲtiemetersbesynchronizedtoacommontime,then
thatneedstobeexplainedmoreclearly.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
144
AgreethatRealͲtimemeteringofintertiesrequirestheuseofcommon
sourcestobothBAs(asperRequirement8).ButgiventhatR1isfocusedon
hourlymegawattͲhourvalues,therequirementbecomesamarket/billing
Iferrorsresultingfromoneofthesedatacomparisonsisexcludedfromtheerror
identificationandmitigationprocess,theerrorsexcludedwillbealsobeexcluded
fromtheperformancemeasurementsandresponsibilityformanagingtheseexcluded
errorswillbepassedtotheinterconnection.Thiswillresultinfrequencycontrol
errormanagedbyallBAAsthroughthefrequencybiastermsoftheirReportingACE.
2. ThecomparisonoftheMWhaccumulatedvaluestelemeteredseparately
withtheMWhvaluesagreeduponbythetwoadjacentBAAs.
1. ThecomparisonofscanͲratedataintegratedovereachhourwiththeMWh
accumulatedvaluestelemeteredseparatelyforeachtielineeachhourfor
thefirstBAA.
Unfortunately,scanͲratevaluescannotbedirectlycomparedwitheachother
becauseofdifferencesbetweenscantimesanddifferencesinscanͲratesbetween
BAAs.ThisOperatingProcesscouldincludeanalysisoftwodifferentdata
comparisonsforeachAdjacentBAAforeachtieline.Thesedatacomparisonsare:
ControlandtheaccuracyoftheperformancemeasuresbasedonReportingACE,i.e.
CPS1,BAAL,DCS,andFRM.ThehourlyMWhstelemeteredtoeachEMSfromthetie
linemetersandagreedtobytheAdjacentBAAsisrequiredtobeavailableandmay
beintheOperatingProcesstoidentifyandmitigateerrorsaffectingtheaccuracyof
scanͲratedatausedinthecalculationofReportingACEforeachBalancingAuthority
Area.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataandhourly
accumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulated
meterdataoftwoadjacentBAAs.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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145
issuenotaRealͲtimeissue.R1shouldberevisedtoclarifytheintent.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
SuggestthattheRealͲtimeinstallationofmetersbelefttoBA
Certification.
TheBACertificationprocessoccursonetime.Theinstallationormodification
ofmetersoccursoveraBalancingAuthority’slifetime.
RequirementR2
Whatismeantbya6secondsamplingrate?IsthatthattheratethataBA
samplesthedatavaluesithasatthemoment,ordoesthe6seconds
representatimedelaybetweenrealͲtimeandACEcalculations?Thiscanbe
anissueforBAsthatmakeuseofmultiͲtiersamples,whereOwnerXsamples
agroupofresourceseveryXͲseconds,thensendsthatblockofdatatotheBA
whowouldsamplealltheblockseveryYͲseconds.
Traditionally,samplingrateswereassociatedwithhowwellacontinuous
functioncanberecreated.Asamplingratethatisslowerthatthefundamental
oscillationsinthecontinuousfunctionwillnotbeabletoreproducethat
originalfunction(theissueofaliasingasexperiencedinwatchingaTV
programinwhichawheelappearstorotateinthewrongdirection).
Whatisthereliabilityjustificationforthisscanrate?
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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146
AcriticalcomponentoftheaccuracyofReportingACEisthetimelinessofthe
datasampled.DrivingAGCusingstaledatawouldbecounterͲproductiveand
couldpossiblycreatereliabilityproblems.Therequirementestablishesa
minimumthresholdofhowoftenthesamplingmustoccur.Entitiescanchose
tosamplemoreoften.AslongasalldatausedtocalculateReportingACEis
sampledwithinsixseconds,thesourcedatashouldnotintroducesignificant
error.
RequirementR4
Thevalueofmonitoringsystemfrequencyisrecognized,butagainas
suggestedinourresponsetoR1,theissueoffrequencymonitoringwould
seemtobebettersuitedtoacertificationprocessratherthantoamandatory
standard.
BalancingAuthorityCertificationprocessesoccuronetime.Theneedfor
accuratefrequencyvaluesconsistentlyisanonͲgoingrealͲtimeissue.
WhatisthejustificationforthevaluesinParts4.1and4.2?
Withrespecttojustification,theSDTutilizedthesamevaluescurrentlywithin
theexistingBALͲ005standardandthebasevaluetheindustryutilizedwhen
listingspecificationsforEMS.
RequirementR5
Thevalueofalarmingisrecognized,butgiventhefactthatR5couldbea
federallaw,thequestioncouldbeasked:
•Whatconstitutes“quality”asinqualityflags?
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
147
•Whatconstitutes“invalid”asininvaliddata?
TheconcernaddressedinR5(alarming)wouldbebetteraddressedin
certification.Thesystemsthatarecertifiedshouldhavealarmingprocesses
builtintothem,customizedtotheneedsoftheBA.
Eachmeterisuniqueinitscapabilityandvaluesitprovides.Itisuponthe
BalancingAuthoritytodeterminewhatvalueswouldbeinvalidfortheir
operatortoreceivefromtheirmetersandwhatindicationscanbeprovidedas
aqualityflag.
RequirementR6
RealͲtimeerrorsintheACEcomponentsarereflectedinvariousother
parameters:
1.SystemFrequency
2.TimeError(evenifTEisnotastandardisstillcomputed)
3.EndofDaycheckouts
4.EndofMonthbilling
AswrittenR6isanexerciseisdatacollectionandmanipulation.
R6doesnotrepresentanydatacollectionandmanipulation.Itestablishesthe
minimumavailabilityofthesystemusedtocalculateReportingACE.The
inabilitytocalculateReportingACEcreatesareliabilityrisktothegrid.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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148
Whataretheimplicationsofanunavailabilitylessthan99.5%,andatwhat
pointsarereliabilityimpacted(andhow)?
Withrespecttojustification,theSDTutilizedthesamevaluescurrentlywithin
theexistingBALͲ005standardandthebasevaluetheindustryutilizedwhen
listingspecificationsforEMS.ReportingACEisanessentialmeasurementof
theBA’scontributiontothereliabilityoftheInterconnection.SinceReporting
ACEisameasureoftheBA’sreliabilityperformanceforBALͲ001,andBALͲ002,
itiscriticalthatReportingACEbesufficientlyavailabletoassurereliability.
RequirementR7
RequirementR7requiresclarification.
Theprocessofmonitoringfordataerrorsandtheprocessformitigatingerrors
thatareidentifiedarebuiltintomodernEMSsystems.
Therequirementaswrittenfocusesonlyonerrors“affectingthescanͲrate
accuracyofdatausedinthecalculationofReportingACE…”.Aswritten,thisis
notalldatausedinACE.Moreover,datadoesnotimpacttheaccuracyofthe
rateofscanning.TherateofscanningisabuiltinfunctiontotheEMS/SCADA
programs.Thedata(goodorbad)isscannedregularly.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6,asmodified)shouldcontainallofthe
informationusedtoidentifyandmitigateerrors.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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149
AswrittenR7doesnotrisetothelevelofaNERCstandardandshouldbe
deleted.
TheDraftingTeambelievestheabsenceofarequirementtoaddress
persistentmetererrorwillallowsignificantmetererrortoremaininthe
calculationandcontrolofthegrid,creatingburdenonothers.
TheintentofR1shouldbetoensurethatacommonmeteringpointbe
identifiedforallRealͲtimeinterͲBAtielines.TheissueofPseudoͲTiesand
DynamicSchedulesisreallyabusinessagreementbetweenthetwoBAsin
cooperationwiththeresourcebeingused,andthereforeisnotastandard
matter.
TheissuebeingaddressedinR1inrelationtoPseudoͲTiesandDynamic
SchedulesistheirinclusioninReportingACE.Thisisparticularlytrueof
allocatedsharesofgenerationresourcesorsupplementaryregulation.Ifthey
arenotincludedinReportingACE,thevalueswillnotbeconsistentand
accurate.
RequirementR8
TherequirementisonPseudoͲtiesandDynamicSchedules,butPseudoͲTies
andDynamicSchedulesarenottielines,theyareoutputvaluesfrom
resources.Insomecasestheseoutputvaluescanbeuseddirectly,butin
othercasesthevaluesareadjustedbytheEMStorepresenttheproportionof
theoutputtobeincorporatedintotheBA’sACE.
TheDraftingTeamisnotsureifyouareraisingaquestionorconcern.Asyou
state,thesevaluesarenecessarytobeincludedinReportingACEandmust
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
CharlesYeung
GroupMemberName
GroupName:
SPP
Entity
ISOStandardsReviewCommittee
SPP
2
150
Region Segments
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
originatefromcommonsourcesforbothBalancingAuthoritiestocontrolto
thesamevalues.
Therequirementtoutilizeacommonsourceforallintertiesisavalid
requirement.
TheagreementsreferredtoinR8areInterconnectionAgreementsand
thereforenotamatterforaNERCstandard.
Interconnectionagreementsarebetweentheelementownerandthe
TransmissionOwnertowhomtheyareinterconnecting.Thisagreementof
commonsourceofReportingACEdatamustoccurbetweenAdjacent
BalancingAuthorities,whoarenotpartiestotheInterconnectionAgreement.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
ChristinaBigelow
TerryBilke
AliMiremadi
GregCampoli
KathleenGoodman
MarkHolman
BenLi
AnswerComment:
TRE
RFC
WECC
NPCC
NPCC
RFC
NPCC
2
2
2
2
2
2
2
AnswerComment:
151
Ingeneral,BPAagreeswiththecurrentdraftofBALͲ005Ͳ1buthassome
concernswithhowBAswillmeettheproposedR7–relatingtoimplementing
an“OperatingProcess”.BPAbelievesthatR7ispoorlywrittenandneedsto
berevisited.
SeefileattachedtoQuestion1fortheSRCcommentsontherationaleand
languageofseveralrequirements.
ERCOT
MISO
CAISO
NYISO
ISONE
PJM
IESO
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
AshleyStringer
JasonSmith
ShannonMickens
GroupMemberName
GroupName:
AnswerComment:
OklahomaMunicipalPower
Authority
SouthwestPowerPool
SouthwestPowerPool
Entity
SPP
SPP
SPP
4
2
2
Region Segments
152
Identificationofcommonsourcesofmeasurement(R8)andrecording(R1)are
BAcertificationitems,notongoingresponsibilitiesthatneedtobechecked
periodically.Newtielinesor“inputs”intotheBAACEcalculationsshouldbe
capturedinFACͲ001.
SPPStandardsReviewGroup
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
Thankyouforyourcomment.TheSDThasmademinormodificationsto
RequirementR7reflectingothercommentsreceived,hopefullythese
modificationshaveprovidedtheclarificationnecessarytoaddressyour
concern.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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153
BACertificationoccursonetime.NewormodifiedtieͲlinevalueshappen
continuallyoverthelifetimeofaBalancingAuthority.FACͲ001dealswith
InterconnectionRequirementsforTransmissionOwnersandGenerator
Owners.TheneedtohaveaccurateReportingACEcalculationsisarealͲtime
functionthatmustoccurtoallowforadequateandaccurateBAAcontrol,asis
thepurposeofBALͲ005.
Thereiscontinuedconfusionregardingthesixsecondscanrate.ABAcan
demonstrateascanrateofitsreceiveddataeverysixseconds,butthereisno
requirementforthedata“madeavailableto”theBAtobescannedata
certainscanrate.Tobemoreclear,therequirementshouldspecifythat
“measurementsshouldbemadebythecommonsource(s)andprovidedto
theBAatleasteverysixsecondsforthecalculationofReportingACE”.Atits
worst,thatshouldresultinanACEcalculationbeingmadeandreportedwith
datanolongerthan12secondsold.
Thankyouforyourcomment.TheSDThasmodifiedtherequirementto
clarifyourintentforthistobeadesignrequirementandthusacapability
requirement.PerformancemeasurementassociatedwithReportingACEis
addressedintheotherBALstandards.
TheRationalforRequirementR3leadswithasentencethathasnobasisinthe
FunctionalModelandshouldbedeleted.TheRCdoesnothaveresponsibility
“forcoordinatingthereliabilityofbulkelectricsystemsformember
BA’s.”TheRCisresponsiblefor“Mitigatingenergyandtransmission
emergencies”amongotherthings.ThestatementmadeintheRationale
overstatestheresponsibilityoftheRCandminimizestheBArole.TheBAhas
primaryresponsibilityformaintainingloadandgenerationbalanceandtheRC
hasauthoritytostepinandprovideassistanceiftheBAisunabletomaintain
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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154
itsobligations.DeletethefirstsentenceoftheRationaleforR3box.What
purposedoesitservetoallowaBAanadditional15minutesafter30minutes
ofaninabilitytocalculateACEbeforenotifyingtheRC.Delete“within45
minutesofthebeginning…ACE”andreplacewith“withoutdelay”.Asstated,
therequirementwouldallowaBAtonotcalculateReportingACEfor44
minutesandthennotifytheRC.OrwouldrequireaBAthatcouldnot
calculateReportingACEfor31minutesbutthenwassuccessfultoalsonotify
theRC.Theintentofthechangeisnotclearandseemstoindicatea
reductioninreliability.
“Withoutdelay”inandofitselfisnotameasureabletimeframe.Previously
therewasnolimitonwhenthenotificationhadtooccur.Thefifteenminutes
afterisareasonabletimeframeandimprovementovernotimelimit.
Whatisthespecificrationaleforrequirementof99.95%(or0.05%outage
allowance=43seconds/day)uptimeforfrequencymeasurement?Issome
reliabilitythresholdcrossedat44secondsoffrequencymeasurement
unavailabilityeachday?IstheintentofR4.2tostillrequirecalibrationofthe
measurementorsimplytoutilizeaprovidedsignificantdigitof.001Hz?The
newR4usestheterm“accuracy”of.001HzratherthantheoldR17
descriptionof“<=0.001Hz”.AlsothemeasurementM4requires
demonstrationof“minimumaccuracy”whichlendsitselftorequiringa
demonstrablecalibrationthatisnotspecificallystatedinR4.Theintended
statementinthemappingdocumentforR17toR4isnotcapturedwellinthe
resultingR4.
Withrespecttojustification,theSDTutilizedthesamevaluescurrentlywithin
theexistingBALͲ005standardandthebasevaluetheindustryutilizedwhen
listingspecificationsforEMS.ReportingACEisanessentialmeasurementof
theBA’scontributiontothereliabilityoftheInterconnection.SinceReporting
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
155
ACEisameasureoftheBA’sreliabilityperformanceforBALͲ001,andBALͲ002,
itiscriticalthatReportingACEbesufficientlyavailabletoassurereliability.
SuggestdeletingR5andsuggestthisrequirementbeevaluatedforinclusionin
theProject2009Ͳ02RealͲTimeMonitoringandAnalysisCapabilitiesworksince
itrelatestoidentifyingsourcesofinccorectinputdata.AnyOperatingProcess
orProceduretoidentify,correct,ormitigateincorrectorlostinputdataoutof
Project2009Ͳ02shouldincludeACEdata.Ifkept,theMeasureM5includesan
additionalrequirementthatthesuspect/garbagedataindicationshouldbe
indicatedonBOTHthecalculatedReportingACEresultaswellasonthe
individualsuspect/garbagedatapoint.WesuggestthatR5shouldinclude
similarlanguagetoM5ifthatistheintent.TheRSAWshouldbeadjusted
basedonchangestoR5orM5.
Thankyouforyourcomment.TheSDTbelievesthatthisrequirementdeals
withflaggingbaddatausedinthecalculationofReportingACE.
SuggestdeletingR6asitisduplicativeandinconflictwithBALͲ001Ͳ2.The
reliabilityimplicationof“knowing”ACEistobeabletoensurebalanceis
maintained.ThatisaccomplishedinCPSandBAALanddoesnotneedtobe
duplicatedhere.Thereporting%doesnotindicateadirectmeasurementof
reliabilityandisadministrativeonly.
BALͲ001Ͳ2measurementsexcludevalueswhenReportingACEisnotavailable.
BALͲ001Ͳ2doesnotlimittheunavailabilityofReportingACE.TheSDTbelieves
thatR6isnecessarytoprovidereliableinformationtotheBAwhichallowsthe
BAtoeffectivelycontrolinordertobalanceDemandandresourcesatalltime.
SuggestdeletingR7andsuggestthisrequirementbeevaluatedforinclusionin
theProject2009Ͳ02RealͲTimeMonitoringandAnalysisCapabilitiesworksince
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
156
itrelatestoidentifyingsourcesofinccorectinputdata.AnyOperatingProcess
orProceduretoidentify,correct,ormitigateincorrectorlostinputdataoutof
Project2009Ͳ02shouldincludeACEdata.
Thankyouforyourcomment.TheSDTbelievesthatthisrequirementdeals
withflaggingbaddatausedinthecalculationofReportingACE.
RegardingR8:Thereisnodemonstrationofthereliabilityimpactofusing
nonͲcommonmetersbetweenBA’sforthepurposeofReportingACE.Infact,
inordertosupportreliability,therequirementshouldspecifythatredundant
sourcesbemadeavailabletobeusedforReportingACE.Lossofthesingle,
commonsourcewouldresultinlostinputtotheACEcalculation.Abest
practicethatmostBA’suseistoidentifyaprimary,commonsourcefor
measurementsandasecondary,commonsourceformeasurementsand
ensureeachadjacentBAisusingthesamecommonsourceatthesame
time.Commonsourcemeasurementsdonotensureaccuracy,theyjustensure
thesameerrorisintroducedinbothadjacentACEcalculationsandtherefore
neteachotherout.
TheSDTagreesthatacommonsourceminimizesanyerrorfromimpacting
anyoneotherthanthetwoBalancingAuthoritiesitisbetween.The
requirementdoesnotdisallowyoufromhavingmorethanonesourcefor
yourmeterdata.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
157
5.PleaseprovideanyissuesyouhaveontheproposedchangetotheBALͲ006Ͳ3standardandaproposedsolution.
JohnFontenotͲBryanTexasUtilitiesͲ1Ͳ
AnswerComment:
none
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
AnswerComment:
WedonotseetheneedtoretainanyoftheBALͲ006requirementsinaNERC
ReliabilityStandard.Standard.InadvertentInterchangeiscalculatedfor
reconciliationpurposeandassuch,doesnothaveanyreliabilityvaluefor
realͲtimeoperationsorpostͲmortemanalysis.Thefacilitiesusedfor
recordinghourlyInadvertentInterchangearemoresuitedtobestipulatedin
theBA’sOrganizationCertificationRequirements;theprocedureto
calculate,reconcileandresolvedisputesoverIntervertentInterchangecan
beputintooperatingguideorevenintheNAESB’sbusinesspractices.
ConsistentwiththeriskͲbasedprinciple,wesuggestthatunlessthereisclear
demonstrationthatfailuretocalculateandreconcileInadvertent
Interchangecanadverselyaffectoperatingreliability,thisstandardshould
beretiredwithitsrequirementstransferredtootherNERCand/orNAESB
documents.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
EmilyRousseauͲMROͲ1,2,3,4,5,6ͲMRO
GroupName:
MROͲNERCStandardsReviewForum(NSRF)
GroupMemberName
Entity
JoeDepoorter
MadisonGas&Electric
AmyCasucelli
XcelEnergy
ChuckLawrence
AmericanTransmissionCompany
ChuckWicklund
OtterTailPowerCompany
TheresaAllard
MinnkotaPowerCooperative,Inc
DaveRudolph
BasinElectricPowerCooperative
KayleighWilkerson
LincolnElectricSystem
JodiJenson
WesternAreaPowerAdministration
LarryHeckert
AlliantEnergy
MahmoodSafi
OmahaPublicUtilityDistrict
ShannonWeaver
MidwestISOInc.
MikeBrytowski
GreatRiverEnergy
BradPerrett
MinnesotaPower
ScottNickels
RochesterPublicUtilities
TerryHarbour
MidAmericanEnergyCompany
TomBreene
WisconsinPublicService
Corporation
TonyEddleman
NebraskaPublicPowerDistrict
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Region Segments
MRO 3,4,5,6
MRO 1,3,5,6
MRO 1
MRO 1,3,5
MRO 1,3,5,6
MRO 1,3,5,6
MRO 1,3,5,6
MRO 1,6
MRO 4
MRO 1,3,5,6
MRO 2
MRO 1,3,5,6
MRO 1,5
MRO 4
MRO 1,3,5,6
MRO 3,4,5,6
MRO 1,3,5
158
R1isembeddedinR2andR3andthereforeunnecessary.
ThesubͲbulletsofR3shouldbebulletsandnotRequirements.Additionally,
theendͲofͲdaycheckshouldbeanagreementofonandoffpeaktotals,not
hourlyvalues.ThereareINTstandardsthatrequireconfirmationofhourly
schedules.
Inthecompliancesection,RROsdonotfilloutmonthlysummaryreports
andsubmitthemtoNERC.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
159
Response:
AmyCasuscelliͲXcelEnergy,Inc.Ͳ1,3,5,6ͲMRO,WECC,SPP
AnswerComment:
ThesubͲrequirementsofR3shouldbebullets,notsubrequirements.
Theendofdaycheckshouldbeanagreementofonandoffpeaktotals,not
hourlyvalues.Confirmationofhourlyschedulesarealreadyrequiredinother
standards.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
Response:
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Region Segments
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC
1,3
BillHutchison
SouthernIllinoisPowerCooperative SERC
1
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
JohnShaver
ArizonaElectricPowerCooperative, WECC 4,5
Inc.
JohnShaver
SouthwestTransmission
WECC 1
Cooperative,Inc.
RyanStrom
BuckeyePower,Inc.
RFC
4
ScottBrame
NorthCarolinaElectricMembership SERC
3,4,5
Corporation
BillWatson
OldDominionElectricCooperative
SERC
3,4
AnswerComment:
WeappreciatetheSDT’seffortstoremoveRequirementR3fromthis
standard.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
160
161
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
AnswerComment:
IntherevisedlanguageforBALͲ006Ͳ3R4,TexasRErecommendsreplacing
theundefinedterm“RegionalReliabilityOrganizationSurveyContact”with
ReliabilityCoordinator.ThismaybeoutsidethepurviewoftheSDTbut
considerationshouldbeprovidedtoclarifytheresponsibilitywhilethe
Standardisbeingconsidered.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
Response:
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
AnswerComment:
AmerensupportsMISO'scommentsforthisquestion
Response:
TheresaRakowskyͲPugetSoundEnergy,Inc.Ͳ1Ͳ
AnswerComment:
Asstatedinquestion#2above,asworded,wedonotbelievethese
requirementsareappropriateforFACͲ001Ͳ3.SinceFACͲ001Ͳ3appliesto
documentedFacilityinterconnectionrequirements,itwouldbemore
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
162
appropriatetorequirethatthedocumentedinterconnectionrequirements
containlanguagestatingthattransmission,generationandendͲuser
interconnectedFacilitiesmustbelocatedwithintheBalancingAuthority
Area’smeteredboundaries.ThiscouldbeaccomplishedbyaddingR3.3
stating“ProceduresforensuringthattransmissionFacilities,generation
FacilitiesandendͲuserFacilitiesarewithintheBalancingAuthorityArea’s
meteredboundaries.”Therequirementtoverifythatexistingfacilitiesare
locatedwiththemeteredboundariesofaBalancingAuthorityAreaismost
appropriatelyassignedtotheTOP,andnottotheTO,GOandtheLSE.
PleasereferenceourresponsetoyourcommentintheFACͲ001question.
Response:
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
AnswerComment:
KCP&LincorporatesbyreferenceitsresponsetoSurveyQuestionNo.2.
Response:
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
GroupName:
ISOStandardsReviewCommittee
GroupMemberName
Entity
Region Segments
CharlesYeung
SPP
SPP
2
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
163
BenLi
IESO
NPCC 2
MarkHolman
PJM
RFC
2
KathleenGoodman
ISONE
NPCC 2
GregCampoli
NYISO
NPCC 2
AliMiremadi
CAISO
WECC 2
TerryBilke
MISO
RFC
2
ChristinaBigelow
ERCOT
TRE
2
AnswerComment:
TheSRCrecommendsthatBALͲ006beretired.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
SeefileattachedtoQuestion1forthefulltextofthecommentstoQuestion
5
Response:
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
AnswerComment:
None.
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
GroupName:
SPPStandardsReviewGroup
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
164
GroupMemberName
Entity
Region Segments
ShannonMickens
SouthwestPowerPool
SPP
2
JasonSmith
SouthwestPowerPool
SPP
2
AshleyStringer
OklahomaMunicipalPower
SPP
4
Authority
AnswerComment:
ThepurposeofBALͲ006Ͳ2(andresultingBALͲ006Ͳ3)donotimpact
reliability.Infact,thisenforceableStandardonlyservestoprovide
administrativemetricsthatarethenusedtofacilitateeitherfinancialorinͲ
kindreimbursements.Inordertomakethisstandardtrulyresultsbasedin
relationtosystemreliability,requirementssuchasaBAshallnotaccumulate
inadvertentinterchangeinexcessofXX,XXXMWhpermonthwouldneedto
becreated.NoBAorRCwillevertakereliabilityactionsorissueOperating
Instructionsinrelationtotheaccumulatedorforecastaccumulated
inadvertentinterchange.ResolutionofinadvertentisanafterͲthefact
reimbursementandnotareliabilityissue.
TheSDThassurveyedtheindustrytodeterminetheoutcomeofBALͲ006.The
majorityoftheindustryhasrecommendedretirementofBALͲ006withcertain
provisionsbeingincludedinanonͲreliabilityprocess.TheSDTwillsubmit
documentstomovethiseffortforwardinthestandardsdevelopmentprocess.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
165
6.PleaseprovideanyissuesyouhaveontheproposedchangetotheFACͲ001Ͳ3standardandaproposedsolution.
JohnFontenotͲBryanTexasUtilitiesͲ1–
AnswerComment:
none
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
AnswerComment:
Inthe“TableofComplianceElements”,theViolationSeverityLevels,R5and
R6shouldcorrectlyrefertoTransmissionOwnerandGeneratorOwner,
respectively(insteadofTransmissionOperatorandGeneratorOperator)
Thankyouforyourcomment,theVSLhasbeencorrected.
Response:
LouisSladeͲDominionͲDominionResources,Inc.Ͳ6Ͳ
GroupName:
Dominion
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
166
GroupMemberName
Entity
Region Segments
RandiHeise
NERCCompliancePolicy
NPCC 5,6
ConnieLowe
NERCCompliancePolicy
SERC
1,3,5,6
LouisSlade
NERCCompliancePolicy
RFC
5,6
ChipHumphrey
PowerGenerationCompliance
SERC
5
NancyAshberry
PowerGenerationCompliance
RFC
5
LarryNash
ElectricTransmissionCompliance
SERC
1,3
CandaceLMarshall
ElectricTransmissionCompliance
SERC
1,3
LarryWBateman
TransmissionCompliance
SERC
1,3
JeffreyNBailey
NuclearCompliance
SERC
5
RussellDeane
NuclearCompliance
NPCC 5
AnswerComment:
DominionsubmittedcommentsͲ2010Ͳ14_2_1_BARCͲ
Unofficial_Comment_FormͲ20150715.docx
Response:
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
AnswerComment:
APSagreeswithmovingtheserequirementsfromBALͲ005tothenewFACͲ
001Ͳ3.APSalsoagreeswiththeproposedrequirementlanguage.APSdoes
notagreethatthemeasurementsofthesenewlyplacedrequirementshave
beencorrectlydrafted.
ATransmissionOperator,GeneratorOperator,orLoadͲServingͲEntity
possessingtheFacilityinterconnectionrequirementsoftheTransmission
Ownertheyareattemptingtointerconnectwithisnotprooftheyarewithina
BalancingAuthorityArea.EvidencetheyarewithinaBalancingAuthorityArea
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
167
wouldbedemonstratedbypossessinganexecutedInterconnection
Agreementorsimilarcontract.Themeasureswillneedtobecorrectedto
reflectthat.TheRSAWwillneedtobecorrectedtolineupwiththose
changes.
TheSDTagreeswithyouandhascorrectedtheVSLandRSAW.
Response:
LeonardKulaͲIndependentElectricitySystemOperatorͲ2Ͳ
AnswerComment:
WeconcurwiththeproposedrevisionstoFACͲ001Ͳ3.
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
AnswerComment:
DonotchangeFACͲ001asthisconfusestheintentoftheoriginal
requirement.Thereisvirtuallynowaytoprovethataparticularcomponentis
withinaBA.TheoriginalrequirementwasintendedtobesureControlAreas
balanced.Thisisdonebyoperatingtocommontiesandperforming
InadvertentInterchangecheckouts.
TheoriginalintentoftherequirementsinBALͲ005wastoassureallFacilities
withintheinterconnectednetworkareaccountedforwithintheboundariesof
aBAA,whichallowsfortheBAtobalanceDemandandresources.TheSDT
willsuggestadditionallanguagechangestoFACͲ001Ͳ3tohelpclarifythe
issues.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
168
Response:
ChrisMattsonͲTacomaPublicUtilities(Tacoma,WA)Ͳ5Ͳ
AnswerComment:
1)FACͲ001Ͳ3R5SevereVSLshouldstate“TheTransmissionOwner……”to
matchR5whichplacesresponsibilityfortherequirementontheTransmission
Owner.CurrentlytheVSLstatestheTransmissionOperatorwillcomply.
2)FACͲ001Ͳ3R6SevereVSLshouldstate“TheGeneratorOwner……”to
matchR6whichplacesresponsibilityfortherequirementontheGenerator
Owner.CurrentlytheVSLstatestheGenerationOperatorwillcomply.
Thankyouforyourcomments,theSDTagreeswithyouandhascorrectedthe
VSLandRSAW.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Region Segments
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
1
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
JohnCiza
169
SouthernCompanyGenerationand SERC
6
EnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC
3
WilliamShultz
SouthernCompanyGeneration
SERC
5
AnswerComment:
ShouldtheSDTdisagreethatexistingprocessesareadequatetoaccomplish
thedesiredoutcome(asdescribedinthecommentstoQuestion#2),thenthe
followingisrecommended:
1.Removetheinserationof4.1.3andR5ͲR7.
2.ModifyR3.2toread“ProceduresfornotifyingtheBA,TOPandRCofnew
ormateriallymodifiedexistinginterconnections.”
3.ModifyR4.2toread“ProceduresfornotifyingtheBA,TOPandRCofnew
interconnections.”
Additionally,ifpossible,itisrecommendedthattherebecontinued
coordinationwiththeFACͲ001teamthatproducedFACͲ001Ͳ2in2014before
anychangestoFACͲ001Ͳ2aremade.
TheSDThasreͲwrittenandcombinedtheoldR1andoldR8intoanew
proposedR7andthusanewmeasurehasbeencreated.However,the
OperatingProcess(newproposedR6)shouldcontainalloftheinformation
usedtoidentifyandmitigateerrors.
TheNERCstaffassignedtothisSDTisincontinuouscontactwiththeother
SDTs.
EleanorEwryͲPugetSoundEnergy,Inc.Ͳ1,3,5ͲWECC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
170
AnswerComment:
Asstatedinquestion#2above,asworded,wedonotbelievethese
requirementsareappropriateforFACͲ001Ͳ3.SinceFACͲ001Ͳ3appliesto
documentedFacilityinterconnectionrequirements,itwouldbemore
appropriatetorequirethatthedocumentedinterconnectionrequirements
containlanguagestatingthattransmission,generationandendͲuser
interconnectedFacilitiesmustbelocatedwithintheBalancingAuthority
Area’smeteredboundaries.ThiscouldbeaccomplishedbyaddingR3.3
stating“ProceduresforensuringthattransmissionFacilities,generation
FacilitiesandendͲuserFacilitiesarewithintheBalancingAuthorityArea’s
meteredboundaries.”Therequirementtoverifythatexistingfacilitiesare
locatedwiththemeteredboundariesofaBalancingAuthorityAreaismost
appropriatelyassignedtotheTOP,andnottotheTO,GOandtheLSE.
TheSDThasmodifiedFACͲ001Ͳ3toclarifytheissues.TheLSEhasbeen
removedfromthestandardbasedontheRBRinitiative.
Response:
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Region Segments
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC
1,3
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
171
BillHutchison
SouthernIllinoisPowerCooperative SERC
1
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
JohnShaver
ArizonaElectricPowerCooperative, WECC 4,5
Inc.
JohnShaver
SouthwestTransmission
WECC 1
Cooperative,Inc.
RyanStrom
BuckeyePower,Inc.
RFC
4
ScottBrame
NorthCarolinaElectricMembership SERC
3,4,5
Corporation
BillWatson
OldDominionElectricCooperative
SERC
3,4
AnswerComment:
WebelieveFACͲ001Ͳ3shouldnotbemodifiedbasedonthereasons
previouslyprovidedinquestion#2.WerecommendtheSDTretirethe
requirementsmovedfromBALͲ005Ͳ0.2bbasedonthereasonscited.Ata
minimum,werecommendtheSDTprovidetechnicaljustificationonwhy
theserequirementsarenecessary.
TheSDT’sintentistoassureallFacilitieswithintheinterconnectnetworkare
accountedforwithintheboundariesofacontrolareaandstronglyfeelsthe
requirementsarenecessarytoallowtheBAtobalanceDemandand
resources.TheSDThasmodifiedFACͲ001Ͳ3tohelpclarifytheissues.
Response:
RachelCoyneͲTexasReliabilityEntity,Inc.Ͳ10Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
172
AnswerComment:
InR5,R6,andR7itseemsduplicitoustoinclude,“meteredboundaries”inthe
phrase“BalancingAuthorityArea’smeteredboundaries”becausethefirst
sentenceofBalancingAuthorityAreadefinitionis“Thecollectionof
generation,transmission,andloadswithinthemeteredboundariesofthe
BalancingAuthority.”
TexasREnoticedtheEvidenceRetentionsectiondoesnotaddressLSEs.
TexasREnoticedtheformatofFACͲ001Ͳ3doesnotfollowthenewNERC
ResultsBasedStandards
Template.
TexasREnoticedtheVSLforR5referstothe“TransmissionOperator”butthe
RequirementisapplicabletotheTransmissionOwner.TheVSLforR6refers
tothe“GeneratorOperator”buttheRequirementisapplicabletothe
GenerationOwner.
TheSDTagreeswithyourassertionthattheuseof“meteredboundaries”may
beduplicitous,however,theSDTbelievestherequirementsarewarranted.
Theinformationmustbemadeavailabletoallpartiestoassurebalanceof
Demandandresources.
TheSDTbelievesthattherequirementappliestoallentitiesinvolvedwith
generationortransmission.TheLSEhasbeenremovedfromthestandard
basedontheRBRinitiative.
TheSDTisawareoftheformattingissueandwillforwardyourcomments
regardingtheformatofFACͲ001Ͳ3totheNERCStandardsCommittee.
TheSDTagreeswithyourcommentabouttheapplicationtoGOandhasmade
thechangeasyousuggested.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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173
Response:
BobThomasͲIllinoisMunicipalElectricAgencyͲ4Ͳ
AnswerComment:
PleaseseecommentunderQustion2above.
Response:
DavidJendrasͲAmerenͲAmerenServicesͲ3Ͳ
AnswerComment:
InouropinionthereappearstobeaninconsistencybetweentheStandard
andtheTableofCompliance.TheApplicabilitysection4.1.1identifiesthe
TransmissionOwnerasaFunctionalentity.RequirementR5identifiesthe
TransmissionOwnerwithresponsibilityforconfirmingfacilitiesarelocated
withintheBAboundaries.However,intheTableofComplianceElements
forrequirementR5,theTransmissionOperatorisidentifiedwiththis
responsibilityundertheSevereVSLcolumn.Webelievethatthe
TransmissionOperatorshouldbechangedtoTransmissionOwnertobe
consistentwiththerequirementsoftheStandard.
TheSDTagreeswithyourcommentabouttheapplicationtoGOandhasmade
thechangeasyousuggested.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
CarolChinnͲFloridaMunicipalPowerAgencyͲ4Ͳ
GroupName:
FMPA
GroupMemberName
Entity
TimBeyrle
CityofNewSmyrnaBeach
JimHoward
LakelandElectric
GregWoessner
KissimmeeUtilityAuthority
LynneMila
CityofClewiston
JavierCisneros
FortPierceUtilityAuthority
RandyHahn
OcalaUtilityServices
DonCuevas
BeachesEnergyServices
StanRzad
KeysEnergyServices
MattCulverhouse
CityofBartow
TomReedy
FloridaMunicipalPowerPool
StevenLancaster
BeachesEnergyServices
MikeBlough
KissimmeeUtilityAuthority
MarkBrown
CityofWinterPark
MaceHunter
LakelandElectric
AnswerComment:
seequestion2
Response:
ScottMcGoughͲGeorgiaSystemOperationsCorporationͲ3Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
174
Region Segments
FRCC 4
FRCC 3
FRCC 3
FRCC 3
FRCC 4
FRCC 3
FRCC 1
FRCC 4
FRCC 3
FRCC 6
FRCC 3
FRCC 5
FRCC 3
FRCC 3
AnswerComment:
175
1.R7seemstonotevenfitwiththestatedpurposeofFACͲ001Ͳ3for
interconnecting(lowercase)toFacilities.Whatisthepurposeof
R7?Capitalizedterm“Interconnection”simplymeans“Whencapitalized,any
oneofthethreemajorelectricsystemnetworksinNorthAmerica:Eastern,
Western,andERCOT.”Readingtherequirementatfacevalue…ifyourloadis
anywhereinEastern,Western,orERCOTInterconnectionareathenconfirm
itsinaBAArea’smeteredboundaries.IstheintentofR7toidentifywhichBA
areatheloadisin?oristheintenttosimplyidentify“yes”itisin“aBAs
Area’smeteredboundary”?Howdoesknowingornotknowingthishave
adverseimpactsonthereliabilityoftheBESwithrespecttothepurposeof
thestandard?
Inaddition,notethatfromNERC’sfilingtoFERC–SupplementalInformation
toPetitionforApprovalofProposedTransmissionOperationsand
InterconnectionReliabilityOperationsandCoordinationReliabilityStandards,
RM15Ͳ16,datedMay12,2015–NERCstatesthat“AnLSEdoesnotownor
operateBulkElectricSystemfacilitiesorequipmentorthefacilitiesor
equipmentusedtoserveendͲusecustomers.21(footnote21ͲThe
DistributionProvideristhefunctionalentitythatprovidesfacilitiesthat
interconnectanendͲusecustomerloadandtheelectricsystemforthe
transferofelectricalenergytotheendͲusecustomer.Ifacompanyregistered
asanLSEalsoownedfacilities,thecompanywouldberegisteredforother
functionsaswell.
2.MeasureM7impliesthatLSEshaveFacilityinterconnection
requirementswhentherearenosuchrequirements,thuscomplicating
complyingwithR7.DoesthedraftingteamintendfortheLSEtoprovidea
copyoftheFacilityinterconnectionrequirementsdocumentstheymayhave
receivedfromtheTOwhenrequestingtointerconnecttothetransmission
owner?
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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176
3.Dependingonunderstandingthetrueintentofthisrequirement,we
wouldbeinfavorforanattestationtobeincludedinthemeasure,butthen…
seemslikeapointless,administrativerequirementthatmeetsP81.
1.TheintentofthisrequirementistoassureallFacilitieswithinthe
interconnectednetworkareaccountedforwithintheboundariesofaBA.The
SDTwillsuggestadditionallanguagechangestoFACͲ001Ͳ3inaccommodate
theinclusionofRequirement1.
2.TheLSEhasbeenremovedfromthestandardbasedontheRBRinitiative.
3.TheSDTagreeswithyourcomment.
Response:
DouglasWebbͲDouglasWebbOnBehalfof:ChrisBridges,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
HaroldWyble,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JamesMcBee,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
JessicaTucker,GreatPlainsEnergyͲKansasCityPowerandLightCo.,3,6,5,1
AnswerComment:
KCP&LincorporatesbyreferenceitsresponsetoSurveyQuestionNo.2.
Response:
LeePedowiczͲNortheastPowerCoordinatingCouncilͲ10ͲNPCC
GroupName:
NPCCͲͲProject2010Ͳ14.2.1Phase2ofBalAuthRelͲbasedControlsͲ
BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
GroupMemberName
Entity
AlanAdamson
NewYorkStateReliabilityCouncil,
LLC
DavidBurke
OrangeandRocklandUtilitiesInc.
GregCampoli
NewYorkIndependentSystem
Operator
GerryDunbar
NortheastPowerCoordinating
Council
MarkKenny
NortheastUtilities
HelenLainis
IndependentElectricitySystem
Operator
RobVance
NewBrunswickPowerCorporation
PaulMalozewski
HydroOneNetworksInc.
BruceMetruck
NewYorkPowerAuthority
LeePedowicz
NortheastPowerCoordinating
Council
DavidRamkalawan
OntarioPowerGeneration,Inc.
BrianRobinson
UtilityServices
WayneSipperly
NewYorkPowerAuthority
EdwardBedder
OrangeandRocklandUtilitiesInc.
MichaelJones
NationalGrid
BrianShanahan
NationalGrid
GlenSmith
EntergyServices,Inc.
RuiDaShu
NortheastPowerCoordinating
Council
ConnieLowe
DominionResourcesServices,Inc.
GuyZito
NortheastPowerCoordinating
Council
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
177
Region Segments
NPCC 10
NPCC 3
NPCC 2
NPCC 10
NPCC 1
NPCC 2
NPCC 9
NPCC 1
NPCC 6
NPCC 10
NPCC 5
NPCC 8
NPCC 5
NPCC 1
NPCC 1
NPCC 1
NPCC 5
NPCC 10
NPCC 5
NPCC 10
178
SilviaParadaMitchell
NextEraEnergy,LLC
NPCC 5
RobertPellegrini
TheUnitedIlluminatingCompany
NPCC 1
KathleenGoodman
ISOͲNewEngland
NPCC 2
AnswerComment:
GiventhatNERCisintheprocessofdelistingtheLSEfromtheFunctional
ModelandtheNERCregistry,suggestrevisingRequirementR7toread“Each
DistributionProviderthatprovidesfacilitiesthatinterconnectacustomer
LoadshallconfirmthateachcustomerLoadiswithinaBalancingAuthority
Area’smeteredboundaries.”MeasureM7wouldneedtoberevised
accordingly.
ThisstandardisunnecessarygiventhefactthatInterconnectionAgreements
arecontractuallegaldocumentsthataddressandspelloutthedetails
addressedbythevariousFACͲ001requirements.
Also,theuseoftherequirement“shalladdress”isnotaclearmandateandis
opentointerpretationbyboththeResponsibleEntityandtheRegional
Enforcemententity.
ThewordinginMeasuresM5thruM7appeartohavebeencopiedfrom
MeasuresM3andM4,mentioning“dated,documentedFacility
interconnectionrequirementsaddressingtheprocedures”asevidencethat
therequirementsaremet.ThewordingintheseMeasuresisappropriatefor
M3andM4,butnotM5thruM7.
TheLSEhasbeenremovedfromthestandardbasedontheRBRinitiative.
TheSDTdisagreeswithyourassertionthatthisRequirementisnotnecessary.
FACͲ001Ͳ3mayrequirecontractuallegaldocumentsbutitdoesnotinsistthat
allelementsoftheInterconnectionbeincludedwithintheboundariesofaBA.
TheSDThasmodifiedFACͲ001Ͳ3tohelpclarifytheissues.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
179
Response:
JasonSnodgrassͲGeorgiaTransmissionCorporationͲ1Ͳ
AnswerComment:
InadditiontothecommentsGTClistedinQuestion2,GTCbelievesthe
responsetoR5asaTOwouldsimplybe"yes"andisunawarehowthisanswer
enhancesreliableoperationoftheBES.Therefore,GTCdoesnotquite
understandtheintentoftheserequirementsastheyarewritten.Confirm
whichBAAreatheTransmissionFacilityislocatedin?Confirmtowhom?GTC
see'sthisasadministrativeinnaturesubjecttoP81criteria.
TheoriginalintentwastoassureallFacilitieswithintheinterconnected
networkareaccountedforwithintheboundariesofaBAallowingforbalance
ofDemandandResources.TheSDTwillsuggestadditionallanguagechanges
toFACͲ001Ͳ3inaccommodatetheinclusionofRequirement1.
Response:
MikeONeilͲNextEraEnergyͲFloridaPowerandLightCo.Ͳ1Ͳ
AnswerComment:
WeappreciatetheworkbytheSDT,butdonotagreewithmovingBALͲ005Ͳ
0.2bRequirementR1toFACͲ001Ͳ3RequirementsR5,R6,andR7.Atthistime,
thewaytheBALͲ005requirementR1readsitposestobemoreofan
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
180
accountingissueversusareliabilityissue.Onealternativesolutionisto
removethelanguagefromthisstandard(FACͲ001Ͳ3)andincludeitinthe
ApplicationGuidelinessection.
TheintentistoassureallFacilitieswithintheinterconnectednetworkare
accountedforwithintheboundariesofaBA.TheSDTwillsuggestadditional
languagechangestoFACͲ001Ͳ3inaccommodatetheinclusionofRequirement
1.
Response:
PayamFarahbakhshͲHydroOneNetworks,Inc.Ͳ1Ͳ
AnswerComment:
HydroOnesupportsallcommentsprovidedbyNPCCRSCregardingthedraft
ofFACͲ001Ͳ3.
Response:
AlbertDiCaprioͲPJMInterconnection,L.L.C.Ͳ2ͲRFC
GroupName:
ISOStandardsReviewCommittee
GroupMemberName
Entity
Region Segments
CharlesYeung
SPP
SPP
2
BenLi
IESO
NPCC 2
MarkHolman
PJM
RFC
2
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
ShawnaSpeerͲColoradoSpringsUtilitiesͲ1Ͳ
GroupName:
ColoradoSpringsUtilities
GroupMemberName
Entity
ShawnaSpeer
ColoradoSpringsUtilities
ShannonFair
ColoradoSpringsUtilities
CharlesMorgan
ColoradoSpringsUtilities
181
Region Segments
WECC 1
WECC 6
WECC 3
AnswerComment:
None.
AndreaJessupͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
KathleenGoodman
ISONE
NPCC 2
GregCampoli
NYISO
NPCC 2
AliMiremadi
CAISO
WECC 2
TerryBilke
MISO
RFC
2
ChristinaBigelow
ERCOT
TRE
2
AnswerComment:
TheSRCrecommendsthatFACͲ001Ͳ2beretired
SeefileattachedtoQuestion1forthefulltextofthecommentstoQuestion
6
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
November10,2015
182
KalebBrimhall
ColoradoSpringsUtilities
WECC 5
AnswerComment:
Againtoillustratethecommentsinresponse#2,FACͲ001isafacility
interconnectionrequirementstandardsoanychangesherewillbeappliedto
FACͲ001applicablefunctionalentitiesdocumentedfacilityinterconnection
requirements.FACͲ001typicallydealswithnewinterconnections,soifthe
intentoftheFACͲ001Ͳ3R5ͲR7istomakesurealltransmission,generation,
andloadarewithinaBAAmeteredboundsthisisnotthecorrectstandard.R7
initsentiretyneedstobemovedtoanotherstandardsinceitisnotclear
whichinterconnectionrequirementitwillfallunder(i.e.TOand/orApplicable
GO).
TheFACͲ001standardcanbeusedtorequiredocumentedfacility
interconnectionrequirementstoaddressBAAmeteredboundsforallentities
seekingtointerconnect.HowevertoenforcethisforBAAmeteredboundsfor
thosefacilitiesthatalreadyexistwithinFACͲ001,thedocumentedfacility
interconnectionrequirementswouldhavetoretroactivelyapplyforthose
facilitiesthatalreadyexist.R5ͲR6needstobemovedtoanotherstandard.
TheintentistoassureallFacilitieswithintheinterconnectednetworkare
accountedforwithintheboundariesofaBA.TheSDTwillsuggestadditional
languagechangestoFACͲ001Ͳ3inaccommodatetheinclusionof
Requirement1.
Response:
JasonSmithͲSouthwestPowerPool,Inc.(RTO)Ͳ2ͲSPP
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183
GroupName:
SPPStandardsReviewGroup
GroupMemberName
Entity
Region Segments
ShannonMickens
SouthwestPowerPool
SPP
2
JasonSmith
SouthwestPowerPool
SPP
2
AshleyStringer
OklahomaMunicipalPower
SPP
4
Authority
AnswerComment:
Thefirst4requirements,whichmakeuptheexistingFACͲ001Ͳ2,are
administrativeandshouldbemovedtocertificationreview.ThenewR5Ͳ7
arenecessaryduetotheremovalfromBALͲ005.Howeverassuggested
earlier,thoserequiremetnsshouldalsobeincludedintheTO’sFacility
InterconnectionRequirementdocumentsanddonotnecessarilyneedtobe
specificReliabilityStandardRequirements.IfR1Ͳ4arekept,werecommend
changingthephrase“shalladdress”inR1Ͳ4to“shallinclude”.
TheintentistoassureallFacilitieswithintheinterconnectednetworkare
accountedforwithintheboundariesofaBA.TheSDTwillsuggestadditional
languagechangestoFACͲ001Ͳ3inaccommodatetheinclusionof
Requirement1.
Response:
ErikaDootͲU.S.BureauofReclamationͲ5Ͳ
AnswerComment:
Reclamationagreeswiththeperiodicreviewteamthatitisimportantto
verifyfacilitiesarewithinthemeteredboundariesofaBalancingAuthority
Areabeforetheyareoperational,butbelievesthattherequirementshould
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ005Ͳ1,BALͲ006Ͳ3,FACͲ001Ͳ3
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beimposedthroughinterconnectionorserviceagreementsratherthana
reliabilitystandard.Asanalternative,FACͲ001Ͳ3R5throughR7andM5
throughM7couldberephrasedtorequireaoneͲtimeconfirmationpriortoa
facilitybeingplacedinservice.
TheintentistoassureallFacilitieswithintheinterconnectednetworkare
accountedforwithintheboundariesofaBA.TheSDTwillsuggestadditional
languagechangestoFACͲ001Ͳ3inaccommodatetheinclusionof
Requirement1.
Response:
.
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AdditionalcommentssubmittedbyLouisSladeͲDominionforQ6:
GiventhatNERCisintheprocessofdelistingtheLSEfromtheFunctionalModelandtheNERCregistry,Dominionsuggests
revisingRequirement7toread“EachLoadͲServingEntityDistributionProviderwithLoadoperatinginanInterconnectionthat
providesfacilitiesthatinterconnectanendͲusecustomerloadshallconfirmthateachendͲusecustomerLoadiswithinaBalancing
AuthorityArea’smeteredboundaries.IfthissuggestionisacceptedbytheSDT,correspondingchangeswouldneedtobemadeto
Measure7.
Response:TheLSEhasbeenremovedfromthestandardbasedontheRBRinitiative.
AdditionalcommentssubmittedbyEmilyRousseau–MRONSRF:
1. TheSDThasmovedtheBALͲ005Ͳ0.2bRequirementR1toFACͲ001sinceitprovidesforidentifyinginterconnectionFacilities
andnotforcalculatingReportingACE.DoyouagreewithmovingthisrequirementintotheFACͲ001Ͳ3standard?Ifnot,
pleaseexplaininthecommentareabelow.
Yes
No
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Comments:
185
Comments:Itisnotnecessarytomovethisrequirement.TheSDTistakingaflawedrequirementandmovingittoanother
location.Therequirementshouldbeimprovedasfollows.
R1.Allgeneration,transmission,andloadoperatingwithinanInterconnectionmustbeincludedwithinthe
meteredboundariesofaBalancingAuthorityArea.
R1.1.EachGeneratorOperatorwithgenerationfacilitiesoperatinginanInterconnectionshallensurethatthose
generationfacilitiesareincludedwithinthemeteredboundariesofaBalancingAuthorityArea.
R1.2.EachTransmissionOperatorwithtransmissionfacilitiesoperatinginanInterconnectionshallensurethat
thosetransmissionfacilitiesareincludedwithinthemeteredboundariesofaBalancingAuthorityArea.
R1.3.EachLoadͲServingEntitywithloadoperatinginanInterconnectionshallensurethatthoseloadsare
includedwithinthemeteredboundariesofaBalancingAuthorityArea.
Therequirementabovewasaconcept(ControlAreaCriteria)thatwassweptintotheV0standard.Theonlywayto
provethateverythingiswithinthemeteredboundsofaBAisviaInadvertentInterchangeaccounting.R1shouldbe
keptasͲis,thesubͲbulletsremovedandthemeasureforR1shouldbe:
M1.TheBalancingAuthoritywasunabletoagreewithanAdjacentBalancingAuthoritywhenperformingInadvertent
InterchangeaccountinganditwasfoundthattheBalancingAuthorityhadanerrorinitsmodelortielinesthat
misstateditsNetActualInterchangevalueinitsInadvertentInterchangeaccounting.
4. PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ005Ͳ1standardandaproposedsolution.
R8isredundantwithwhencomparedtothesuggestedwordingaboveforBALͲ005Ͳ1R1andBALͲ006R3.
IfthechangetoR1aboveismade,R7isnolongernecessary.
Themeasureofthisrequirementisnotlogsorvoicerecordings. NSIisalready checkedwithInadvertentAccounting
andtheINTstandards. Theprocess thatwasproposedinR7couldbethevalidationandmeasureforR1
Comments:
TheSRCdoesnotagreewiththeproposeddefinitionofAGC.
TheSRCrecommendsthefollowingdefinitionforAGC:
Yes
No
1. TheSDThasmodifiedthedefinitionofAutomaticGenerationControl(AGC).Doyouagreethatthismodifieddefinition
betterrepresentstheSDTintenttomakingresourcesmoreinclusivethanjustthetraditionalgenerationresources?Ifnot,
pleaseexplaininthecommentareabelow.
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BALͲ005Ͳ1
R1.EachBalancingAuthorityshallensurethathaveaprocesstooperateto common,accurateeachTieͲLines,PseudoͲ
Ties,andDynamicSchedules withitsanAdjacentBalancingAuthorities.isequippedwithamutually agreedupontime
synchronizedcommonsourcetodeterminehourly megawattͲhourvalues
TheproposedR1shouldbeshortenedandmergedwithR7. Thereneednotbemention of“mutuallyagreedupon”nor“time
synchronized”. AGCandACEuserealͲtimevalues, nothourlyvalues.
AdditionalcommentssubmittedbyISOStandardsReviewCommittee
187
Rationale:
1. TheBALͲ005definitionsshouldnotincludeanyreferencestoAutomaticTimeErrorCorrection(IATEC).
BALͲ005isaNERCstandardapplicabletoallInterconnectionsͲnotoneofthemanyregionallyͲapprovedstandards.This
standardisapprovedforallBAsunlesstheBAisinaregioninwhichthestandardissupersededbyaFERCͲapproved
regionalstandard.Assuch,theSRCbelievesthedefinitionandreferencestoAutomaticTimeErrorCorrection(IATEC)
shouldbedeletedandlefttotheregionallyͲapprovedregionalstandard.
2. Thefollowingphrases/termsusedintheproposeddefinitionofAGCareambiguousornotprecise.
x Centrallylocatedequipment
Thisphraseshouldbedeleted.
ThereisnojustificationtolinkthedefinitionofAutomaticGenerationControl(AGC)toagivenlocationgiven
thatAGCisaprocess(software)notequipment(hardware).
x …thatautomaticallyadjusts…
Thisphraseshouldbereworded.
ThereisnodirectlinkbetweenanAGCsignalandtheresponseofaresource.Aswrittenthefailureofa
resourcetorespondtoanAGCsignalwouldconstituteaviolationonthepartoftheBA.
ItwouldbemorecorrecttostatethatAGC“isusedtoadjustresources”.
x …maintainReportingACE…
Thisphraseshouldbedeleted.
Automatic Generation Control (AGC): AprocessdesignedandusedtoadjustaBalancingAuthority’sresources
tomeettheBA’sbalancingrequirementsasrequiredbyapplicableNERCReliabilityStandards.
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x
AGCdoesnot“utilize”resources,but–rather–evaluatesresourceutilizationwithinabalancingAuthority
Areatoensurethatloadandresourcesremaininbalance.Morespecifically,resourcesareaninputto
AGC.
Thesentenceitselfisapartiallistofsupplyresourcesandthereforenotcriticaltodefiningthetermitself.
ResourcesutilizedunderAGC…
Thissentenceshouldbedeleted.
Comments:
TheSRCsupportsdeletingtheR1requirementsinBALͲ005Ͳ0.2b,andrecommendsplacingtheobligationina
certificationrequirement.
Rationale:(alsoseeresponsetoQuestion6below)
1. BALͲ005Ͳ0.2bR1addressesAGC.R1.1–R1.3addressadministrativeitemsthataregenerallycontainedwithin
InterconnectionAgreementsaslegaltermsandconditions–notasreliabilityͲrelatedconcernsorissues
2. IfR1anditssubͲrequirementswerereliabilitystandards,theywouldresultinanunnecessaryannualexchangeof
paperworkbetweenandamongassetowners,BAsandtheERO.
Yes
No
188
x
2. TheSDThasmovedtheBALͲ005Ͳ0.2bRequirementR1toFACͲ001sinceitprovidesforidentifyinginterconnectionFacilities
andnotforcalculatingReportingACE.DoyouagreewithmovingthisrequirementintotheFACͲ001Ͳ3standard?Ifnot,
pleaseexplaininthecommentareabelow.
x
AGCisnotdesignedforreportingpurposes.AGCisdesignedtoassistinthecontrolofaBA’sbalancingofits
resourcestoitsNERCmandatedbalancingobligations.
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Comments:
TheSRCopposestheproposaltomoveBALͲ006Ͳ2RequirementR3intoBALͲ005Ͳ3.
TheSRCrecommendsthatBALͲ006bedeleted.
Rationale:
TheSRCopposesthisproposalforthefollowingreasons:
1. Thetwostandardsaddressissuesthatareintwodifferenttimehorizons(BALͲ005isarealtimehorizon(MW),while
BALͲ006isanhourlyhorizon(MWhr).Tocombinethetwostandardsintoasinglestandardwillconfusetheobjectives
ofeachofthesetimehorizonsandtheassociatedfunctions.
2. Thecollectionofhourly(InadvertentInterchange)dataproposedbythetransferredrequirement(R3)doesnotaffect
therealtimecalculationofReportingACE.BALͲ006isastandardforInadvertentInterchangewhichisanafterͲtheͲ
factaccountingfunctionasopposedtoBALͲ005whichisaboutrealͲtimereliabilityfunction.
3. Realtimemeteringofinterconnectingpointsisbetterhandledasacertificationissuegiventhatsuchmeteringis
relativelystaticandstableanddoesnotrequirecontinuousthecontinuousreviewmandatedbyareliabilitystandard.
4. TheobjectiveofR3is not clear as currently proposed. Specifically, it is unclear if R3 is meant:
x AsaproceduralmandatethatBAsuseasinglerealͲtimepointofmeteringforinterconnectionpointsusedinthe
ACEcalculation?
x Asadatareportingmandateonmeters,thatallinterconnectionpointmetershavetheabilitytocomputehourly
readings?or
x AsadatareportingmandateonBAstocommunicateinformationoninterconnectionpointsonceanhourto
adjacentBAs(inwhichcasethereisaneedforatimecriteria–e.g.sendtheinformationwithin4hoursofthe
clockhour).
3. TheSDThasmovedtheBALͲ006Ͳ2RequirementR3intoBALͲ005Ͳ3sincethisrequirementdirectlyimpactsanentity’sability
tocalculateanaccurateReportingACE.DoyouagreewithmovingthisrequirementintotheproposedBALͲ005Ͳ1standard?
Ifnot,pleaseexplaininthecommentareabelow.
Yes
No
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TheintentofR1isnotaccuracy(commonsourcemeteringdoesnotaddressaccuracy).TheintentofR1istoensureazeroͲ
sumdataensembleforallACEs.
Comments:
TheSRCprovidescommentsontherationaleandlanguageofseveralrequirementsbelowbyrequirement.
RequirementR1
TheSRCrecommends:
x TherationaleforR1bereconsideredandcorrected.
x ThereferencesinR1to“timeͲsynchronizedcommonsource”and“hourlymegawattͲhourvalues“bedeleted.
Rationale
TheSRCquestionsthefollowingtextintheproposed“RationaleforRequirementR1”:
x TheintentofR1istoprovideaccuracy…
x R1…usedin…ReportingACE,hourlyinadvertentenergy,andFrequencyResponsemeasurements
x It[R1]specifiesneedfor…instantaneousandhourlyintegrated…tielineflowvalues
x Commondatasourcerequirementsalsoapply…
TheSRCalsonotesthatNERC’sIndependentExpertReviewPanelrecommendedBALͲ006forretirementbecause“Thisis
onlyforenergyaccounting.CoveredbyTaggingrequirements.”
4. PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ005Ͳ1standardandaproposedsolution.
Additionally,ifRequirementR1ismeantasadatareportingrequirement,itshouldhavebeenconsideredforretirement
undertheParagraph81concept.Ifnot,additionalclarificationisneeded,e.g.,isitacertificationrequirementthat
mandateshardware.
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ContractͲbasedbillingmetersusedforInadvertentInterchangearenotnecessarilythesameastherealtimecommonsource
metersusedinACE.ThetextofR1isnotpreciseinwhatisthespecificobjectiveforR1.TherationalestatesR1isfor
instantaneousandhourlytieflowvaluesbutthetextofR1statesitis“…todeterminehourlymegawattͲhourvalues.”
ThefinalsentenceintheRationalesectionregardingofotherR1applicationsissuperfluousandshouldbedeleted.
TheSRCquestionsthefollowingtext:
x …timeͲsynchronizedcommonsource…
x …todeterminehourlymegawattͲhourvalues
Thephrase“timeͲsynchronizedcommonsource”requiresexplanation.
IftwoBAsareusingacommon(MW)sourceforrealtimeflows,thenbydefinitionthevaluesaresynchronized.If,onthe
otherhand,R1onlyappliestoHourly(Billing)values(MWh)thephraseisstillsuperfluous.However,ifthephraseismeantto
mandatethatallinterͲtiemetersbesynchronizedtoacommontime,thenthatneedstobeexplainedmoreclearly.
TheSRCagreesthatrealtime(MW)meteringofinterͲtiesrequirestheuseofcommonsourcestobothBAs(asper
Requirement8).ButgiventhatR1isfocusedonhourlymegawattͲhourvalues,therequirementbecomesamarket/billing
issuenotarealtimeissue.Inshort,theSDTisaskedtorewriteR1inafashionthatclarifiestheintent.
RequirementR2
TheSRCrecommends:
x TherationaleforR2bereconsideredandrevised.
Rationale
Theproposed“RationaleforRequirementR2”overstatesitsjustification.Specificallytherationalestatesthatwithout
frequency“…theBAoperatorwilllacksituationalawarenessandwillbeunabletomakecorrectdecisionswhenmaintaining
reliability.”
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TheSRCdoesnotagreethataBAwouldbe“unable”tomakecorrectdecisions.TheSRCacknowledgesthatdecisionͲmaking
regardingimpactsonandthesupportforfrequencymaybemoredifficult.However,thisdifficultydoesnotthreatenthe
reliabilityoftheinterconnectionastielineflowswillstillbemonitoredbyTOPsandsystemfrequencywillbemonitoredby
otherBAs,TOPsandRCs.
RequirementR4
TheSRCrecommendsthatsubͲrequirements(4.1and4.2)bedeleted.
Rationale:
TheSRCrecognizesthevalueofmonitoringsystemfrequency,butsuggeststhatthemonitoringoftheavailabilityand
accuracyoffrequencyͲmonitoringequipmentisadatacollectionandreportingexercisethatisonerousandadministrativein
nature.Suchrequirementswouldbebettersuitedtobeaddressedaspartofacertificationprocessoringuidance
documentsthanasamandatoryreliabilitystandard.
InlieuofdeletingthesubͲrequirements,theSRCrequeststhejustificationforthevaluesinR4.1and4.2,andforthebenefits
toreliabilitythatistobeobtainedthroughtheproposedrequirements.
RequirementR5
TheSRCrecommends:
x R5beaddressedaspartofacertificationprocess.
x TherationaleforR5bereconsideredandrevised.
Rationale
TheSRCbelievesR5(alarming)wouldbebetteraddressedincertificationthanaspartofareliabilitystandardthatissubject
tocontinuousreviewasareliabilitystandardrequirement.Thesystemsthatarecertifiedshouldhavealarmingprocesses
builtintothemthatarecustomizedtotheneedsoftherespectiveBA.Suchsystems,oncereviewed,arerelativelystaticand
notsubjecttofrequentmodification.Additionally,althoughtheSRCrecognizesthevaluesofalarming,itisconcernedthat,in
thecontextofamandatoryreliabilitystandard,subjectivitywillbeintroducedregardingwhatconstitutes“quality”for
qualityflags,and“invalid”forinvaliddata.Withoutanobjectivemeasurefortheaforementionedterms,RequirementR5
losesanyvalueasareliabilitystandard.
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RequirementR6
TheSRCrecommendsrequirementR6bedeleted.
Rationale
TheSRCrecognizesthevalueofmonitoringACEcalculation,butsuggeststhemonitoringoftheavailabilityofthesoftware,
etc.utilizedtocalculateACEisadatacollectionandreportingexercisethatisonerousandadministrativeinnature.Such
requirementsarebetteraddressedduringthecertificationprocessandinguidancedocumentationthanaspartofa
mandatoryreliabilitystandard.
TheSRCisconcernedthatcertaintermssuchas“availablesystem”createambiguity,e.g.,whatwouldconstitutean
“availablesystem.”Neithertherequirementnorthemeasurementmakesclearwhatanavailablesystemisnorwhena
systemwouldbedeemedunavailable,e.g.,isasystem“unavailable”tocomputeACEifasingledatasampleisunavailable?
Orwhentheentiresystemisunavailable.
RequirementR7
TheSRCrecommends:
x R7bedeleted.
x TherationaleforR7bereconsideredandrevised.
Rationale
TheSRCsuggeststhataswritten,R7isanadministrativerequirementthatdoesnotrisetothelevelofaNERCstandardand
shouldbedeleted.
ShouldRequirementR7beretained,theSRCcommentsthattheobjectiveandobligationofaBAunderrequirementR7is
ambiguousandrequiresadditionalexplanation/clarification.Additionally,theprocessofmonitoringforandmitigatingdata
Theproposed“RationaleforRequirementR5”states“Whenanoperatorquestionsthevalidityofdata,actionsaredelayed
andtheprobabilityofadverseeventsoccurringcanincrease.”Whiletheabovecouldbetrue,thereisnoobjectiveevidence
tosupportthestatementandthereforethestatementshouldbedeleted.
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194
errorsthatareidentifiedarebuiltintomodernEMSsystems.Thus,theSDTproposedrequirementforan“Operating
Process,”whichisnotadefinedterminGlossaryandshouldnotbeconsideredapropernouninthisrequirement,wouldbe
redundantofexistingprocessesandfunctionality.Further,therequirementfocusesonlyonerrors“affectingthescanͲrate
accuracyofdatausedinthecalculationofReportingACE…”TheSRCassertsthatdata(inandofitself)generallydoesnot
impacttheaccuracyoftherateofscanning,whichisabuiltinfunctiontotheEMS/SCADAprograms.Thedata(goodorbad)
isscannedregularly.
TheRationaleforR7statesthat“…WithoutaprocesstoaddresspersistenterrorsintheACEcalculation,theoperatorcan
losetrustinthevalidityofReportingACEresultingindelayedorincorrectdecisionsregardingthereliabilityofthebulk
electricsystem.”
TheSRCrequeststhateitherjustificationandsupportforthisstatementbeprovided,orthestatementbedeletedfromthe
rationalesection.
RequirementR8
TheSRCrecommends:
x R8bereviewedandrevised.
x TheRationaleforR8bereconsideredandrevised.
Rationale
TheSRCbelievesthattheissueofcommonsourcemeteringforallinterͲties,andofagreementsonallocatingresourcesas
pseudoͲtiesordynamicschedulesisbesthandledasInterconnectionAgreementsorcertificationratherthanasareliability
standard.
TheSRCnotesthatRequirement8includesPseudoͲtiesandDynamicSchedulesbutPseudoͲtiesandDynamicSchedulesare
nottielines,butareoutputvaluesfromresources.Insomecasestheseoutputvaluescanbeuseddirectly,butinothercases
thevaluesareadjustedbytheEMStorepresenttheproportionoftheoutputtobeincorporatedintotheBAsACE,andthus
donotderivefromcommonsourcemeters.
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Comments:
TheSRCrecommendsthatBALͲ006beretired.
Rationale:
InadvertentInterchangeisanaccountingmetricnotreliabilitymetric.
TheBALͲ006requirementsareadministrativemandatesrelatedtoafterͲtheͲfactaccountingshouldberetiredunder
Paragraph81.
195
TheRationaleforR8statesthat“…Whendatasourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingin
delayedorincorrectoperatoraction.”TheSRCobjectstothisstatement.
Ifdatasourcesarenotcommon,thentheACEvaluesinanInterconnectionnolongerformazeroͲsumsystem.Suchanerror
canonlybeidentifiedinatieͲlinebytieͲlinecheck.TheresultcanbeallBAsmeettheControlPerformancerequirements,
buttheInterconnectionitselfisexperiencinganimbalancethatresultsinoffͲschedulefrequencyandtimeerror.TheSRC
wouldpointoutthatanyinaccuraciesorerrorsintheACEcomponentsarereflectedinvariousotherparameters:
x SystemFrequency
x TimeError
x EndofDaycheckouts
x EndofMonthbilling
Thus,noconfusionwouldresultandthisshouldbedeletedformtherationale
TheRationaleforRequirementR8alsostates“TheintentofRequirementR8istoprovideaccuracyinthemeasurementand
calculations.”Commonsourcemeteringdoesnotprovideaccuracyasthedatacanstillbeinerror.Whatcommonsource
meteringdoesprovideisazeroͲsumsystem.Thus,theSRCrequeststhattherationalebemodifiedtomoreaccurately
reflecttheimpactofdatasourcesonaccuracy.
5. PleaseprovideanyissuesyouhaveontheproposedchangetotheBALͲ006Ͳ3standardandaproposedsolution.
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Endofreport
196
Comments:
TheSRCrecommendsthatFACͲ001Ͳ2beretired(alsoseeresponsetoQuestion2above)
Rationale:
1. RequirementsR1–R4addressadministrativeitemsthataregenerallycontainedwithinInterconnectionAgreementsas
legaltermsandconditions–notasreliabilityͲrelatedconcernsorissues
2. RequirementsR5ͲR7arecertificationissues.Iftheserequirementswerereliabilitystandards,theywouldresultinan
unnecessaryannualexchangeofpaperworkbetweenandamongassetowners,BAsandtheERO.
AnyvalueofInadvertentInterchangeisasaninternalcontrolprocessandwouldbestbememorializedinaformotherthana
standard.
6. PleaseprovideanyissuesyouhaveontheproposedchangetotheFACͲ001Ͳ3standardandaproposedsolution.
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BALͲ005Ͳ1–BalancingAuthorityControl
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARPostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentperiodandinitialballot
July30,2015
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithadditionalballot
November2015–
January2016
Finalballot
January2016
NERCBoardadoption
February2016
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page1of18
BALͲ005Ͳ1–BalancingAuthorityControl
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:
RationaleforModificationofAGC:TheoriginaldefinitionofAGCreflects"howto"control
andautomaticallyadjustequipmentinaBalancingAuthorityAreaanddoesnotreflectthe
currenttechnologynortheevolutionoftheindustryfroma“ControlArea”toa“Balancing
Area”.Inaddition,itwastellingtheentity"howtodoit"ratherthanallowingtheentityto
performthenecessaryfunctionsinthemosteffectiveandreliablemanner.
Thenewdefinitionreflectsaprocessandallowstheentitytheflexibilitytoperformthe
necessaryfunctioninthemosteffectiveandreliablemannertoaddresssuchprocess
withoutbeinginstructedon"howtodoit".
AutomaticGenerationControl(AGC):AprocessdesignedandusedtoadjustaBalancing
AuthorityAreas’DemandandresourcestohelpmaintaintheReportingACEinthatofa
BalancingAuthorityAreawithin theboundsrequiredbyapplicableNERCReliabilityStandards.
ActualFrequency(FA):TheInterconnectionfrequencymeasuredinHertz(Hz).
ActualNetInterchange(NIA):ThealgebraicsumofactualmegawatttransfersacrossallTie
Lines,includingPseudoͲTies,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection.ActualmegawatttransfersonasynchronousDCtielinesthataredirectly
connectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
ScheduledNetInterchange(NIS):Thealgebraicsumofallscheduledmegawatttransfers,
includingDynamicSchedules,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection,includingtheeffectofscheduledramps.Scheduledmegawatttransfers
onasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionareexcludedfrom
ScheduledNetInterchange.
InterchangeMeterError(IME):Aterm,normallyzero,usedintheReportingACEcalculationto
compensatefordataorequipmenterrorsaffectinganyothercomponentsoftheReportingACE
calculation.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page2of18
BALͲ005Ͳ1–BalancingAuthorityControl
AutomaticTimeErrorCorrection(IATEC):TheadditionofacomponenttotheACEequationfor
theWesternInterconnectionthatmodifiesthecontrolpointforthepurposeofcontinuously
payingbackPrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.Automatic
TimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
whenoperatinginAutomaticTimeErrorCorrectionMode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|Bi|andL10,
0.2*|Bi|чLmaxчL10.
x
x
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare
(RMS)valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragiven
year.Thebound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
x
x
Y=Bi/BS.
H=Numberofhoursusedtopaybackprimaryinadvertentinterchangeenergy.Thevalue
ofHissetto3.
x
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
x
x
x
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲBi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontime
monitor,where: ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontime
monitorcontrolcenterclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲ
Peakaccumulationaccountingisrequired,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
ReportingACE:ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError
(ACE)measuredinMWincludesthedifferencebetweentheBalancingAuthorityArea’sActual
NetInterchangeanditsScheduledNetInterchange,plusitsFrequencyBiasSettingobligation,
pluscorrectionforanyknownmetererror.IntheWesternInterconnection,ReportingACE
includesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page3of18
BALͲ005Ͳ1–BalancingAuthorityControl
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
=
ActualNetInterchange.
x NIA
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
=
ScheduledFrequency.
x FS
x IME
=
InterchangeMeterError.
x IATEC
=
AutomaticTimeErrorCorrection.
AllNERCInterconnectionsoperateusingtheprinciplesofTieͲlineBias(TLB)Controlandrequire
theuseofanACEequationsimilartotheReportingACEdefinedabove.Anymodification(s)to
thisspecifiedReportingACEequationthatis(are)implementedforallBAAsonan
Interconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBiascontrol
willprovideavalidalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofall
BAAs’generation,load,andlossisthesameastotalInterconnectiongeneration,load,
andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimes
andthesumofallBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEterm
correctsforknownmeteringorcomputationalerrors.)
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’ReportingACEequation(oralternatecontrolprocesses).
RationaleforModificationofBalancingAuthority:TheSDThasrecommendedtochange
thedefinitionofAutomaticGenerationControl(AGC)andtobeconsistent,withthechange
toAGC,theSDTrecommendschangingthedefinitionofaBalancingAuthority.Inaddition,
Project2015Ͳ04AlignmentofTermsSDTbroughttoourattentionoftheinconsistentuseof
"loadͲinterchangeͲgeneration"andthroughtheAlignmentofTermsprojectitwas
recommendaSDTassociatedwithaBALStandardaddresstheissue.Theproposedchanges
reflectsaBalancingAuthority.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page4of18
BALͲ005Ͳ1–BalancingAuthorityControl
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourcebalancewithinaBalancingAuthorityArea,andsupports
Interconnectionfrequencyinrealtime.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page5of18
BALͲ005Ͳ1–BalancingAuthorityControl
Whenthisstandardhasreceivedballotapproval,thetextboxeswillbemovedtothe
SupplementalMaterialSectionofthestandard.
A. Introduction
1.
Title:
BalancingAuthorityControl
2.
Number:
BALͲ005Ͳ1
3.
Purpose: Thisstandardestablishesrequirementsforacquiringdatanecessaryto
calculateReportingAreaControlError(ReportingACE).Thestandardalsospecifiesa
minimumperiodicity,accuracy,andavailabilityrequirementforacquisitionofthe
dataandforprovidingtheinformationtotheSystemOperator.
4.
Applicability:
4.1. FunctionalEntities:
4.1.1. BalancingAuthority
EffectiveDate: See Implementation Plan for BAL-005-1
B. Requirements and Measures
RationaleforRequirementR1:RealͲtimeoperationofaBalancingAuthorityrequires
realͲtimeinformation.AsufficientscanrateiskeytoanOperator’strustinrealͲtime
information.Withoutasufficientscanrate,anoperatormayquestiontheaccuracyof
dataduringevents,whichwoulddegradetheoperator’sabilitytomaintainreliability.
R1.
TheBalancingAuthorityshalluseadesignscanrateofnomorethansixsecondsin
acquiringdatanecessarytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M1. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthedata
necessarytocalculateReportingACEwasdesignedtobescannedatarateofnomore
thansixseconds.Acceptableevidencemayincludehistoricaldata,datedarchivefiles;
ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR2:TheRCisresponsibleforcoordinatingthereliabilityof
bulkelectricsystemsformemberBA’s.WhenaBAisunabletocalculateitsACEforan
extendedperiodoftime,thisinformationmustbecommunicatedtotheRCwithin15
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page6of18
BALͲ005Ͳ1–BalancingAuthorityControl
minutesthereaftersothattheRChassufficientknowledgeofsystemconditionstoassess
anyunintendedreliabilityconsequencesthatmayoccuronthewidearea.
R2.
ABalancingAuthoritythatisunabletocalculateReportingACEformorethan30Ͳ
consecutiveminutesshallnotifyitsReliabilityCoordinatorwithin45minutesofthe
beginningoftheinabilitytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M2. EachBalancingAuthoritywillhavedatedrecordstoshowwhenitwasunableto
calculateReportingACEformorethan30consecutiveminutesandthatitnotifiedits
ReliabilityCoordinatorwithin45minutesofthebeginningoftheinabilitytocalculate
ReportingACE.Suchevidencemayinclude,butisnotlimitedto,datedvoice
recordings,operatinglogs,orothercommunicationdocumentation.
RationaleforRequirementR3:Frequencyisthebasicmeasurementforinterconnection
health,andacriticalcomponentforcalculatingReportingACE.Withoutsufficient
availablefrequencydatatheBAoperatorwilllacksituationalawarenessandwillbe
unabletomakecorrectdecisionswhenmaintainingreliability.
R3.
EachBalancingAuthorityshallusefrequencymeteringequipmentforthecalculation
ofReportingACE:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
3.1. thatisavailableaminimumof99.95%foreachcalendaryear;and,
3.2. withaminimumaccuracyof0.001Hz.
M3. TheBalancingAuthorityshallhaveevidencesuchasdateddocumentsorother
evidenceinhardcopyorelectronicformatshowingthefrequencymetering
equipmentusedforthecalculationofReportingACEhadaminimumavailabilityof
99.95%foreachcalendaryearandhadaminimumaccuracyof0.001Hzto
demonstratecompliancewithRequirementR3.
RationaleforRequirementR4:SystemoperatorsutilizeReportingACEasaprimary
metrictodetermineoperatingactionsorinstructions.WhendatainputsintotheACE
calculationareincorrect,theoperatorshouldbemadeawarethroughvisualdisplay.
Whenanoperatorquestionsthevalidityofdata,actionsaredelayedandtheprobability
ofadverseeventsoccurringcanincrease.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page7of18
BALͲ005Ͳ1–BalancingAuthorityControl
R4.
TheBalancingAuthorityshallmakeavailabletotheoperatorinformationassociated
withReportingACEincluding,butnotlimitedto,qualityflagsindicatingmissingor
invaliddata.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtimeOperations]
M4. EachBalancingAuthorityAreashallhaveevidencesuchasagraphicaldisplayordated
alarmlogthatprovidesindicationofdatavalidityfortherealͲtimeReportingACE
basedonboththecalculatedresultandalloftheassociatedinputstherein.
RationaleforRequirementR5:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthatReportingACE
besufficientlyavailabletoassurereliability.
R5.
EachBalancingAuthority’ssystemusedtocalculateReportingACEshallbeavailablea
minimumof99.5%ofeachcalendaryear.[ViolationRiskFactor:Medium][Time
Horizon:OperationsAssessment]
M5. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
systemnecessarytocalculateReportingACEhasaminimumavailabilityof99.5%for
eachcalendaryear.Acceptableevidencemayincludehistoricaldata,datedarchive
files;ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR6:ReportingACEisameasureoftheBA’sreliability
performanceforBALͲ001,andBALͲ002.Withoutaprocesstoaddresspersistenterrorsin
theACEcalculation,theoperatorcanlosetrustinthevalidityofReportingACEresulting
indelayedorincorrectdecisionsregardingthereliabilityofthebulkelectricsystem.
R6.
EachBalancingAuthoritythatiswithinamultipleBalancingAuthorityInterconnection
shallimplementanOperatingProcesstoidentifyandmitigateerrorsaffectingthe
accuracyofscanratedatausedinthecalculationofReportingACEforeachBalancing
AuthorityArea.[ViolationRiskFactor:Medium][TimeHorizon:SameͲdayOperations
]
M6. EachBalancingAuthorityshallhaveacurrentOperatingProcessmeetingthe
provisionsofRequirementR6andevidencetoshowthattheprocesswas
implemented,suchasdatedcommunicationsorincorporationinSystemOperator
taskverification.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page8of18
BALͲ005Ͳ1–BalancingAuthorityControl
RationaleforRequirementR7:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedataiscriticalto
calculatingReportingACEthatisconsistentbetweenBalancingAuthorities.Whendata
sourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingindelayedor
incorrectoperatoraction.
TheintentofRequirementR7Part7.1istoprovideaccuracyinthemeasurementand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
instantaneousvaluesforthetieͲlinemegawattflowvaluesbetweenBalancingAuthority
Areas.CommondatasourcerequirementsalsoapplytoinstantaneousvaluesforpseudoͲ
tiesanddynamicschedules,andcanextendtomorethantwoBalancingAuthoritiesthat
participateinallocatingsharesofagenerationresourceinsupplementaryregulation,for
example.
TheintentofRequirementR7Part7.2istoenableaccuracyinthemeasurementsand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
hourlyaccumulatedvaluesforthetimesynchronizedtielineMWhvaluesagreedͲupon
betweenBalancingAuthorityAreas.ThesetimesynchronizedagreedͲuponvaluesare
necessaryforuseintheOperatingProcessrequiredinR6toidentifyandmitigateerrors
inthescanͲratevaluesusedinReportingACE.
R7.
EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,andDynamic
SchedulewithanAdjacentBalancingAuthorityisequippedwith:[ViolationRisk
Factor:Medium][TimeHorizon:OperationsPlanning]
7.1. acommonsourcetoprovideinformationtobothBalancingAuthoritiesforthe
scanratevaluesusedinthecalculationofReportingACE;and,
7.2. atimesynchronizedcommonsourcetodeterminehourlymegawattͲhourvalues
agreedͲupontoaidintheidentificationandmitigationoferrors.
M7. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodemonstrateacommonsourceforthecomponentsusedinthe
calculationofReportingACEwithitsAdjacentBalancingAuthority.
C. Compliance
1.
ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliabilityStandards.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page9of18
BALͲ005Ͳ1–BalancingAuthorityControl
1.2. EvidenceRetention
Thefollowingevidenceretentionperiod(s)identifytheperiodoftimean
entityisrequiredtoretainspecificevidencetodemonstratecompliance.For
instanceswheretheevidenceretentionperiodspecifiedbelowisshorterthan
thetimesincethelastaudit,theComplianceEnforcementAuthoritymayask
anentitytoprovideotherevidencetoshowthatitwascompliantforthefullͲ
timeperiodsincethelastaudit.
Theapplicableentityshallkeepdataorevidencetoshowcomplianceas
identifiedbelowunlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
x
Theapplicableentityshallkeepdataorevidencetoshowcompliancefor
thecurrentyear,plusthreepreviouscalendaryears.
1.3. ComplianceMonitoringandAssessmentProcesses:
AsdefinedintheNERCRulesofProcedure,“ComplianceMonitoringand
AssessmentProcesses”referstotheidentificationoftheprocessesthatwill
beusedtoevaluatedataorinformationforthepurposeofassessing
performanceoroutcomeswiththeassociatedReliabilityStandard.
1.4. AdditionalComplianceInformation
None
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page10of18
N/A
Lower VSL
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
45minutesofthe
beginningofthe
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto50
minutesfromthe
beginningofthe
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Medium
R2. RealͲtime
Operations
VRF
Medium
Time
Horizon
R1. RealͲtime
Operations
R#
Table of Compliance Elements
BALͲ005Ͳ1–BalancingAuthorityControl
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin50
minutesofthe
beginningofan
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto55
minutesfromthe
beginningofan
N/A
Moderate VSL
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
55minutesofthe
beginningofan
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto60
minutesfromthe
beginningofan
N/A
High VSL
Violation Severity Levels
Page11of18
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin60
minutesofthe
beginningofan
inabilitytocalculate
ReportingACE.
BalancingAuthority
wasusingadesign
scanrateofgreater
thansixsecondsto
acquirethedata
necessarytocalculate
ReportingACE.
Severe VSL
Medium
R4. RealͲtime
Operations
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.95%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.94%ofthe
calendaryear.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Medium
R3. RealͲtime
Operations
inabilitytocalculate
ReportingACE.
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.94%ofthe
calendaryearbutwas
availablegreaterthan
orequalto99.93%of
thecalendaryear.
inabilitytocalculate
ReportingACE.
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.93%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.92%ofthe
calendaryear.
inabilitytocalculate
ReportingACE.
Page12of18
TheBalancing
Authorityfailedto
makeavailable
information
indicatingmissingor
invaliddata
associatedwith
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEfailed
tohaveaminimum
accuracyof0.001Hz.
Or
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.92%ofthe
calendaryear
Medium
R7. Operations
Planning
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.5%ofthecalendar
yearbutwas
availablegreater
thanorequalto99.4
%ofthecalendar
year.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Medium
R6. SameͲday
Operations
R5. Operations Medium
Assessment
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.4%ofthecalendar
yearbutwas
availablegreaterthan
orequalto99.3%of
thecalendaryear.
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.3%ofthecalendar
yearbutwas
availablegreater
thanorequalto99.2
%ofthecalendar
year.
Page13of18
TheBalancing
Authorityfailedto
useacommonsource
forTieͲLines,PseudoͲ
tiesandDynamic
TheBalancing
Authorityfailedto
implementan
OperatingProcessto
identifyandmitigate
errorsaffectingthe
scanͲrateaccuracyof
datausedinthe
calculationof
ReportingACE.
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.2%ofthecalendar
year.
ReportingACEtoits
operators.
Date
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Version
Version History
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
BALͲ005Ͳ1–BalancingAuthorityControl
Action
Change Tracking
Page14of18
TheBalancing
Authorityfailedto
useatime
synchronized
commonsourcefor
hourlymegawatt
hourvaluesthatare
agreedͲupontoaidin
theidentificationand
mitigationoferrors.
Or
Scheduleswithits
AdjacentBalancing
Authorities
April 1, 2005
August 8, 2005
December 19,
2007
January 16,
2008
February 12,
2008
October 29,
2008
May 13, 2009
March 8, 2012
September 13,
2012
February 7,
2013
0
0
0a
0a
0b
0.1b
0.1b
0.2b
0.2b
0.2b
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
FERC approved – Updated Effective Date
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
FERC approved – Updated Effective Date
BOT approved errata changes; updated version
number to “0.1b”
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Removed “Proposed” from Effective Date
Effective Date
Adopted by NERC Board of Trustees
Draft#2ofStandardBALͲ005Ͳ1:October,2015
February 8,
2005
0
BALͲ005Ͳ1–BalancingAuthorityControl
Addition
Errata
Addition
Errata
Replacement
Errata
Addition
Errata
New
New
Page15of18
November21,
2013
R2andassociatedelementsapprovedby FERC for
retirementaspartoftheParagraph81 project
(Project2013Ͳ02)effectiveJanuary21,2014.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page16of18
Standards Attachments
NOTE:Usethissectionforattachmentsorotherdocumentsthatarereferencedinthestandardaspartoftherequirements.These
shouldappearaftertheendofthestandardtemplateandbeforetheSupplementalMaterial.Iftherearenone,deletethissection.
0.2b
BALͲ005Ͳ1–BalancingAuthorityControl
SupplementalMaterial
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page17of18
SupplementalMaterial
Rationale
UponBoardapproval,thetextfromtherationaleboxeswillbemovedtothissection.
Draft#2ofStandardBALͲ005Ͳ1:October,2015
Page18of18
BALͲ005Ͳ1–BalancingAuthorityControl
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefirstpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithaninitial
ballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARPostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentperiodandinitialballot
July30,2015
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithadditionalballot
November2015–
January2016
Finalballot
January2016
NERCBoardadoption
February2016
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page1of20
BALͲ005Ͳ1–BalancingAuthorityControl
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:
RationaleforModificationofAGC:TheoriginaldefinitionofAGCreflects"howto"control
andautomaticallyadjustequipmentinaBalancingAuthorityAreaanddoesnotreflectthe
currenttechnologynortheevolutionoftheindustryfroma“ControlArea”toa“Balancing
Area”.Inaddition,itwastellingtheentity"howtodoit"ratherthanallowingtheentityto
performthenecessaryfunctionsinthemosteffectiveandreliablemanner.
Thenewdefinitionreflectsaprocessandallowstheentitytheflexibilitytoperformthe
necessaryfunctioninthemosteffectiveandreliablemannertoaddresssuchprocess
withoutbeinginstructedon"howtodoit".
AutomaticGenerationControl(AGC):AprocessdesignedandusedtoadjustaBalancing
AuthorityAreas’DemandandresourcestohelpmaintaintheReportingACEinthatofa
BalancingAuthorityAreawithin theboundsrequiredbyapplicableNERCReliabilityStandards.
EquipmentthatautomaticallyadjustsgenerationinaBalancingAuthorityAreafromacentral
locationtomaintaintheBalancingAuthority’sinterchangescheduleplusFrequencyBias.AGC
mayalsoaccommodateautomaticinadvertentpaybackandtimeerrorcorrection.
ActualFrequency(FA):TheInterconnectionfrequencymeasuredinHertz(Hz).
ActualNetInterchange(NIA):ThealgebraicsumofactualmegawatttransfersacrossallTie
Lines,includingPseudoͲTies,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection.ActualmegawatttransfersonasynchronousDCtielinesthataredirectly
connectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
ScheduledNetInterchange(NIS):Thealgebraicsumofallscheduledmegawatttransfers,
includingDynamicSchedules,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection,includingtheeffectofscheduledramps.Scheduledmegawatttransfers
onasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionareexcludedfrom
ScheduledNetInterchange.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page2of20
BALͲ005Ͳ1–BalancingAuthorityControl
InterchangeMeterError(IME):Aterm,normallyzero,usedintheReportingACEcalculationto
compensatefordataorequipmenterrorsaffectinganyothercomponentsoftheReportingACE
calculation.
AutomaticTimeErrorCorrection(IATEC):TheadditionofacomponenttotheACEequationfor
theWesternInterconnectionthatmodifiesthecontrolpointforthepurposeofcontinuously
payingbackPrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.Automatic
TimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
whenoperatinginAutomaticTimeErrorCorrectionMode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|Bi|andL10,
0.2*|Bi|чLmaxчL10.
x
x
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare
(RMS)valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragiven
year.Thebound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
x
x
Y=Bi/BS.
H=Numberofhoursusedtopaybackprimaryinadvertentinterchangeenergy.Thevalue
ofHissetto3.
x
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
x
x
x
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲBi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontime
monitor,where: ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontime
monitorcontrolcenterclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲ
Peakaccumulationaccountingisrequired,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
ReportingACE:ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError
(ACE)measuredinMWincludesthedifferencebetweentheBalancingAuthorityArea’sActual
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page3of20
BALͲ005Ͳ1–BalancingAuthorityControl
NetInterchangeanditsScheduledNetInterchange,plusitsFrequencyBiasSettingobligation,
pluscorrectionforanyknownmetererror.IntheWesternInterconnection,ReportingACE
includesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
x NIA
=
ActualNetInterchange.
=
ScheduledNetInterchange.
x NIS
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
x IATEC
=
AutomaticTimeErrorCorrection.
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartotheReporting
ACEdefinedabove.Anymodification(s)tothisspecifiedReportingACEequationthatis(are)
implementedforallBAAsonanInterconnectionandis(are)consistentwiththefollowingfour
principlesofTieLineBiascontrolwillprovideavalidalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofall
BAAs’generation,load,andlossisthesameastotalInterconnectiongeneration,load,
andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimes
andthesumofallBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEterm
correctsforknownmeteringorcomputationalerrors.)
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’controlReportingACEequations(oralternatecontrolprocesses).
RationaleforModificationofBalancingAuthority:TheSDThasrecommendedtochange
thedefinitionofAutomaticGenerationControl(AGC)andtobeconsistent,withthechange
toAGC,theSDTrecommendschangingthedefinitionofaBalancingAuthority.Inaddition,
Project2015Ͳ04AlignmentofTermsSDTbroughttoourattentionoftheinconsistentuseof
"loadͲinterchangeͲgeneration"andthroughtheAlignmentofTermsprojectitwas
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page4of20
BALͲ005Ͳ1–BalancingAuthorityControl
recommendaSDTassociatedwithaBALStandardaddresstheissue.Theproposedchanges
reflectsaBalancingAuthority.
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourceload-interchange-generationbalancewithinaBalancing
AuthorityArea,andsupportsInterconnectionfrequencyinrealtime.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page5of20
BALͲ005Ͳ1–BalancingAuthorityControl
Whenthisstandardhasreceivedballotapproval,thetextboxeswillbemovedtothe
SupplementalMaterialSectionofthestandard.
A. Introduction
1.
Title:
BalancingAuthorityControl
2.
Number:
BALͲ005Ͳ1
3.
Purpose: Thisstandardestablishesrequirementsforacquiringdatanecessaryto
calculateReportingAreaControlError(ReportingACE).Thestandardalsospecifiesa
minimumperiodicity,accuracy,andavailabilityrequirementforacquisitionofthe
dataandforprovidingtheinformationtotheSystemOperator.
4.
Applicability:
4.1. FunctionalEntities:
4.1.1. BalancingAuthority
EffectiveDate: See Implementation Plan for BAL-005-1
B. Requirements and Measures
RationaleforRequirementR1:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedata(meaning
datafromthesamesource)iscriticaltocalculatingReportingACEthatisconsistent
betweenBalancingAuthorities.Whendatasourcesarenotcommon,confusioncanbe
createdbetweenBAsresultingindelayedorincorrectoperatoraction.
TheintentofRequirementR1istoprovideaccuracyinthemeasurementsand
calculationsusedinReportingACE,hourlyinadvertentenergy,andFrequencyResponse
measurements.Itspecifiestheneedforcommonmeteringpointsforinstantaneousand
hourlyintegratedvaluesforthetielinemegawattflowvaluesbetweenBalancing
AuthorityAreas.Commondatasourcerequirementsalsoapplywhenmorethantwo
BalancingAuthoritiesparticipateinallocatingsharesofagenerationresourceorin
supplementaryregulation,forexample.
R1.
EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,andDynamic
SchedulewithanAdjacentBalancingAuthorityisequippedwithamutuallyagreedͲ
upontimesynchronizedcommonsourcetodeterminehourlymegawattͲhourvalues.
[ViolationRiskFactor:Medium][TimeHorizon:OperationsPlanning]
1.1. ThesevaluesshallbeexchangedbetweenAdjacentBalancingAuthorities.
M1. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodetermineiftheBalancingAuthorityanditsadjacentBalancing
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page6of20
BALͲ005Ͳ1–BalancingAuthorityControl
Authorityhaveagreeduponatimesynchronizedcommonsourcetodetermine
megawattͲhourvalues.
RationaleforRequirementR12:RealͲtimeoperationofaBalancingAuthorityrequires
realͲtimeinformation.AsufficientscanrateiskeytoanOperator’strustinrealͲtime
information.Withoutasufficientscanrate,anoperatormayquestiontheaccuracyof
dataduringevents,whichwoulddegradetheoperator’sabilitytomaintainreliability.
R2.R1.
TheBalancingAuthorityshalluseadesignscanrateofnomorethansixseconds
inacquiringdatanecessarytocalculateReportingACE.[ViolationRiskFactor:
Medium][TimeHorizon:RealͲtimeOperations]
M2.M1. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
datanecessarytocalculateReportingACEwasdesignedtobescannedatarateofno
morethansixseconds.Acceptableevidencemayincludehistoricaldata,dated
archivefiles;ordatafromotherdatabases,spreadsheets,ordisplaysthat
demonstratecompliance.
RationaleforRequirementR23:TheRCisresponsibleforcoordinatingthereliabilityof
bulkelectricsystemsformemberBA’s.WhenaBAisunabletocalculateitsACEforan
extendedperiodoftime,thisinformationmustbecommunicatedtotheRCwithin15
minutesthereaftersothattheRChassufficientknowledgeofsystemconditionstoassess
anyunintendedreliabilityconsequencesthatmayoccuronthewidearea.
R3.R2.
ABalancingAuthoritythatisunabletocalculateReportingACEformorethan30Ͳ
consecutiveminutesshallnotifyitsReliabilityCoordinatorwithin45minutesofthe
beginningoftheaninabilitytocalculateReportingACE.[ViolationRiskFactor:
Medium][TimeHorizon:RealͲtimeOperations]
M3.M2. EachBalancingAuthoritywillhavedatedrecordstoshowwhenitwasunableto
calculateReportingACEformorethan30consecutiveminutesandthatitnotifiedits
ReliabilityCoordinatorwithin45minutesofthebeginningoftheaninabilityto
calculateReportingACE.Suchevidencemayinclude,butisnotlimitedto,datedvoice
recordings,operatinglogs,orothercommunicationdocumentation.
RationaleforRequirementR34:Frequencyisthebasicmeasurementforinterconnection
health,andacriticalcomponentforcalculatingReportingACE.Withoutsufficient
availablefrequencydatatheBAoperatorwilllacksituationalawarenessandwillbe
unabletomakecorrectdecisionswhenmaintainingreliability.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page7of20
BALͲ005Ͳ1–BalancingAuthorityControl
R4.R3.
EachBalancingAuthorityshallusefrequencymeteringequipmentforthe
calculationofReportingACE:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
4.1.3.1.
thatisavailableaminimumof99.95%foreachcalendaryear;and,
4.2.3.2.
withaminimumaccuracyof0.001Hz.
M4.M3. TheBalancingAuthorityshallhaveevidencesuchasdateddocumentsorother
evidenceinhardcopyorelectronicformatshowingthefrequencymetering
equipmentusedforthecalculationofReportingACEhadaminimumavailabilityof
99.95%foreachcalendaryearandhadaminimumaccuracyof0.001Hzto
demonstratecompliancewithRequirementR34.
RationaleforRequirementR45:SystemoperatorsutilizeReportingACEasaprimary
metrictodetermineoperatingactionsorinstructions.WhendatainputsintotheACE
calculationareincorrect,theoperatorshouldbemadeawarethroughvisualdisplay.
Whenanoperatorquestionsthevalidityofdata,actionsaredelayedandtheprobability
ofadverseeventsoccurringcanincrease.
R5.R4.
TheBalancingAuthorityshallmakeavailabletotheoperatorinformation
associatedwithReportingACEincluding,butnotlimitedto,qualityflagsindicating
missingorinvaliddata.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
M5.M4. EachBalancingAuthorityAreashallhaveevidencesuchasagraphicaldisplayor
datedalarmlogthatprovidesindicationofdatavalidityfortherealͲtimeReporting
ACEbasedonboththecalculatedresultandalloftheassociatedinputstherein.
RationaleforRequirementR56:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthatReportingACE
besufficientlyavailabletoassurereliability.
R6.R5.
EachBalancingAuthority’ssystemusedtocalculateReportingACEshallbe
availableaminimumof99.5%ofeachcalendaryear.[ViolationRiskFactor:Medium]
[TimeHorizon:OperationsAssessment]
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page8of20
BALͲ005Ͳ1–BalancingAuthorityControl
M6.M5. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
systemnecessarytocalculateReportingACEhasaminimumavailabilityof99.5%for
eachcalendaryear.Acceptableevidencemayincludehistoricaldata,datedarchive
files;ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR67:ReportingACEisameasureoftheBA’sreliability
performanceforBALͲ001,andBALͲ002.Withoutaprocesstoaddresspersistenterrorsin
theACEcalculation,theoperatorcanlosetrustinthevalidityofReportingACEresulting
indelayedorincorrectdecisionsregardingthereliabilityofthebulkelectricsystem.
R7.R6.
EachBalancingAuthoritythatiswithinamultipleBalancingAuthority
InterconnectionshallimplementanOperatingProcesstoidentifyandmitigateerrors
affectingthescanͲrateaccuracyofscanͲratedatausedinthecalculationofReporting
ACEforeachBalancingAuthorityArea.[ViolationRiskFactor:Medium][Time
Horizon:SameͲdayOperations]
M7.M6. EachBalancingAuthorityshallhaveacurrentOperatingProcessmeetingthe
provisionsofRequirementR67andevidencetoshowthattheprocesswas
implemented,suchasdatedcommunicationsorincorporationinSystemOperator
taskverification.
RationaleforRequirementR78:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedataiscriticalto
calculatingReportingACEthatisconsistentbetweenBalancingAuthorities.Whendata
sourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingindelayedor
incorrectoperatoraction.
TheintentofRequirementR78Part7.1istoprovideaccuracyinthemeasurementand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
instantaneousvaluesforthetieͲlinemegawattflowvaluesbetweenBalancingAuthority
Areas.CommondatasourcerequirementsalsoapplytoinstantaneousvaluesforpseudoͲ
tiesanddynamicschedules,andcanextendtomorethantwoBalancingAuthoritiesthat
participateinallocatingsharesofagenerationresourceinsupplementaryregulation,for
example.
TheintentofRequirementR7Part7.2istoenableaccuracyinthemeasurementsand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
hourlyaccumulatedvaluesforthetimesynchronizedtielineMWhvaluesagreedͲupon
betweenBalancingAuthorityAreas.ThesetimesynchronizedagreedͲuponvaluesare
necessaryforuseintheOperatingProcessrequiredinR6toidentifyandmitigateerrors
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page9of20
BALͲ005Ͳ1–BalancingAuthorityControl
inthescanͲratevaluesusedinReportingACE.
R7.
EachBalancingAuthorityshallensurethateachTieͲLine,PseudoͲTie,andDynamic
SchedulewithanAdjacentBalancingAuthorityisequippedwith:EachBalancing
AuthorityshallagreewithanAdjacentBalancingAuthorityonacommonsourcefor
respectiveTieͲLines,PseudoͲTies,andDynamicSchedulesandshallimplementthat
commonsourcetoprovidecommoninformationtobothBalancingAuthoritiesforthe
calculationofReportingACE.[ViolationRiskFactor:Medium][TimeHorizon:
OperationsPlanning]
7.1. amutuallyagreedͲuponcommonsourcetoprovidecommoninformationto
bothBalancingAuthoritiesforthescanratevaluesusedinthecalculationof
ReportingACE;and,
7.2. amutuallyagreedͲupontimesynchronizedcommonsourcetodeterminehourly
megawattͲhourvaluesagreedͲupontoaidintheidentificationandmitigationof
errors.
M8.M7. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodemonstratedetermineifitagreedwithitsadjacentBalancing
Authorityonaacommonsourceforthecomponentsusedinthecalculationof
ReportingACEwithitsAdjacentBalancingAuthority.
C. Compliance
1.
ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliabilityStandards.
1.2. EvidenceRetention
Thefollowingevidenceretentionperiod(s)identifytheperiodoftimean
entityisrequiredtoretainspecificevidencetodemonstratecompliance.For
instanceswheretheevidenceretentionperiodspecifiedbelowisshorterthan
thetimesincethelastaudit,theComplianceEnforcementAuthoritymayask
anentitytoprovideotherevidencetoshowthatitwascompliantforthefullͲ
timeperiodsincethelastaudit.
Theapplicableentityshallkeepdataorevidencetoshowcomplianceas
identifiedbelowunlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page10of20
BALͲ005Ͳ1–BalancingAuthorityControl
x
Theapplicableentityshallkeepdataorevidencetoshowcompliancefor
thecurrentyear,plusthreepreviouscalendaryears.
1.3. ComplianceMonitoringandAssessmentProcesses:
AsdefinedintheNERCRulesofProcedure,“ComplianceMonitoringand
AssessmentProcesses”referstotheidentificationoftheprocessesthatwill
beusedtoevaluatedataorinformationforthepurposeofassessing
performanceoroutcomeswiththeassociatedReliabilityStandard.
1.4. AdditionalComplianceInformation
None
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page11of20
Medium
R12. RealͲtime
Operations
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Medium
Operations
Planning
R1.
VRF
Time
Horizon
R#
Table of Compliance Elements
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
Violation Severity Levels
Page12of20
BalancingAuthority
wasusingadesign
scanrateofgreater
thansixsecondsto
acquirethedata
necessaryto
TheBalancing
Authorityfailedto
providethe
megawatthour
valuestoitsAdjacent
Balancing
Authorities.
Or
TheBalancing
Authorityfailedto
agreeuponatime
synchronized
commonsourcefor
hourlymegawatt
hourvalueswithits
AdjacentBalancing
Authorities
Severe VSL
Medium
R34. RealͲtime
Operations
TheBalancing
Authority’s
frequencymetering
equipmentusedfor
thecalculationof
ReportingACEwas
availablelessthan
99.95%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
45minutesofthe
beginningofthean
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto50
minutesfromthe
beginningofthean
inabilitytocalculate
ReportingACE.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Medium
R23. RealͲtime
Operations
BALͲ005Ͳ1–BalancingAuthorityControl
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.94%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
50minutesofthe
beginningofan
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto55
minutesfromthe
beginningofan
inabilitytocalculate
ReportingACE.
TheBalancing
Authority’s
frequencymetering
equipmentusedfor
thecalculationof
ReportingACEwas
availablelessthan
99.93%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
55minutesofthe
beginningofan
inabilitytocalculate
ReportingACEbut
notifieditsReliability
Coordinatorinless
thanorequalto60
minutesfromthe
beginningofan
inabilitytocalculate
ReportingACE.
Page13of20
TheBalancing
Authority’sfrequency
Or
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.92%ofthe
calendaryear
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
60minutesofthe
beginningofan
inabilitytocalculate
ReportingACE.
calculateReporting
ACE.
Medium
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.5%ofthe
calendaryearbut
wasavailablegreater
thanorequalto99.4
%ofthecalendar
year.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
R56. Operations Medium
Assessment
R45. RealͲtime
Operations
99.94%ofthe
calendaryear.
BALͲ005Ͳ1–BalancingAuthorityControl
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.4%ofthecalendar
yearbutwas
availablegreater
thanorequalto99.3
%ofthecalendar
year.
N/A
99.93%ofthe
calendaryear.
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.3%ofthe
calendaryearbut
wasavailablegreater
thanorequalto99.2
%ofthecalendar
year.
N/A
99.92%ofthe
calendaryear.
Page14of20
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.2%ofthecalendar
year.
TheBalancing
Authorityfailedto
makeavailable
information
indicatingmissingor
invaliddata
associatedwith
ReportingACEtoits
operators.
meteringequipment
usedforthe
calculationof
ReportingACEfailed
tohaveaminimum
accuracyof0.001Hz.
Medium
R78. Operations
Planning
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Medium
R67. SameͲday
Operations
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
N/A
N/A
N/A
N/A
Page15of20
TheBalancing
Authorityfailedto
implementthe
commonsourceto
providecommon
informationtoboth
Balancing
Authorities.
Or
TheBalancing
Authorityfailedto
useagreeupona
commonsourcefor
tTieͲlLines,PseudoͲ
tiesandDynamic
Scheduleswithits
AdjacentBalancing
Authorities
TheBalancing
Aauthorityfailedto
implementan
OperatingProcessto
identifyandmitigate
errorsaffectingthe
scanͲrateaccuracyof
datausedinthe
calculationof
ReportingACE.
February 8,
2005
April 1, 2005
0
0
Action
Effective Date
Adopted by NERC Board of Trustees
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Date
Version
Version History
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
BALͲ005Ͳ1–BalancingAuthorityControl
New
New
Change Tracking
Page16of20
TheBalancing
Authorityfailedto
useagreeuponatime
synchronized
commonsourcefor
hourlymegawatt
hourvaluesthatare
agreedͲupontoaidin
theidentificationand
mitigationoferrors.
Or
December 19,
2007
January 16,
2008
February 12,
2008
October 29,
2008
May 13, 2009
March 8, 2012
September 13,
2012
February 7,
2013
November21,
2013
0a
0a
0b
0.1b
0.1b
0.2b
0.2b
0.2b
0.2b
R2andassociatedelementsapprovedby FERC for
retirementaspartoftheParagraph81 project
(Project2013Ͳ02)effectiveJanuary21,2014.
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
FERC approved – Updated Effective Date
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
FERC approved – Updated Effective Date
BOT approved errata changes; updated version
number to “0.1b”
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Removed “Proposed” from Effective Date
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
August 8, 2005
0
BALͲ005Ͳ1–BalancingAuthorityControl
Addition
Errata
Addition
Errata
Replacement
Errata
Addition
Errata
Page17of20
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page18of20
Standards Attachments
NOTE:Usethissectionforattachmentsorotherdocumentsthatarereferencedinthestandardaspartoftherequirements.These
shouldappearaftertheendofthestandardtemplateandbeforetheSupplementalMaterial.Iftherearenone,deletethissection.
BALͲ005Ͳ1–BalancingAuthorityControl
SupplementalMaterial
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page19of20
SupplementalMaterial
Rationale
UponBoardapproval,thetextfromtherationaleboxeswillbemovedtothissection.
Draft#21ofStandardBALͲ005Ͳ1:OctoberJuly,2015
Page20of20
FAC-001-3 — Facility Interconnection Requirements
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthesecondpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithan
additionalballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentandinitialballot
July30,2015
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithadditionalballot
November2015–
January2016
Finalballot
January2016
NERCBoardadoption
February2016
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 1 of 12
FAC-001-3 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 2 of 12
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 3 of 12
FAC-001-3 — Facility Interconnection Requirements
RationaleforRequirementR3.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthetransmissionwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under3.3,theTransmissionOwnerisresponsibleforconfirmingthat
thepartyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
RationaleforRequirementR4.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthegenerationwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under4.3,theGeneratorOwnerisresponsibleforconfirmingthatthe
partyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 4 of 12
FAC-001-3 — Facility Interconnection Requirements
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified generation Facilities are within a
Balancing Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The applicable Functional Entity shall keep data or evidence to show compliance
as identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 5 of 12
FAC-001-3 — Facility Interconnection Requirements
Complaint
1.4. Additional Compliance Information
None
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Page 6 of 12
Lower
Long-term
Planning
R1
N/A
Draft#2ofStandardFACͲ001Ͳ3:October,2015
VRF
Time
Horizon
R#
Table of Compliance Elements
Lower VSL
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 7 of 12
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Draft#2ofStandardFACͲ001Ͳ3:October,2015
R2
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 8 of 12
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Lower
Long-term
Planning
R4
The Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
The Generator Owner
failed to address one
part of Requirement
R4 Part 4.1 through
Part 4.3.
N/A
N/A
Draft#2ofStandardFACͲ001Ͳ3:October,2015
Lower
Long-term
Planning
R3
FAC-001-3 — Facility Interconnection Requirements
The Generator Owner
failed to address two
parts of Requirement
R4 Part 4.1 through
Part 4.3.
The Transmission
Owner failed to
address two parts of
Requirement R3 Part
3.1 through Part 3.3.
Page 9 of 12
The Generator Owner
failed to address
Requirement R4 Part
4.1 through Part 4.3.
The Transmission
Owner failed to
address Requirement
R3 Part 3.1 through
Part 3.3.
Draft#2ofStandardFACͲ001Ͳ3:October,2015
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
FAC-001-3 — Facility Interconnection Requirements
Page 10 of 12
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 11 of 12
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 12 of 12
FAC-001-3 — Facility Interconnection Requirements
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthesecondpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithan
additionalballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentandinitialballot
July30,2015
Anticipated Actions
Date
45Ͳdayformalcommentperiodwithadditionalballot
November2015–
January2016
Finalballot
January2016
NERCBoardadoption
February2016
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 1 of 13
FAC-001-3 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 2 of 13
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
4.1.3
5.
Load Serving Entities
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 3 of 13
FAC-001-3 — Facility Interconnection Requirements
RationaleforRequirementR3.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthetransmissionwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under3.3,theTransmissionOwnerisresponsibleforconfirmingthat
thepartyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
RationaleforRequirementR4.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthegenerationwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under4.3,theGeneratorOwnerisresponsibleforconfirmingthatthe
partyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 4 of 13
FAC-001-3 — Facility Interconnection Requirements
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified generation Facilities are within a
Balancing Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
R5. Each Transmission Owner with Transmission Facilities operating in an Interconnection
shall confirm that each Transmission Facility is within a Balancing Authority Area’s
metered boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term
Planning]
M5. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R5.
R6. Each Generator Owner with generation Facilities operating in an Interconnection shall
confirm that each generation Facility is within a Balancing Authority Area’s metered
boundaries. [Violation Risk Factor: Medium] [Time Horizon: Long-Term Planning]
M6. Each Generator Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R6.
R7. Each Load-Serving Entity with Load operating in an Interconnection shall confirm that
each Load is within a Balancing Authority Area’s metered boundaries. [Violation Risk
Factor: Medium] [Time Horizon: Long-Term Planning]
M7. Each applicable Load Serving Entity shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R7.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 5 of 13
FAC-001-3 — Facility Interconnection Requirements
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The applicable Functional EntityTransmission Owner and applicable Generator
Owner shall keep data or evidence to show compliance as identified below unless
directed by its CEA to retain specific evidence for a longer period of time as part
of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Page 6 of 13
Lower
Long-term
Planning
R1
N/A
Lower VSL
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
VRF
Time
Horizon
R#
Table of Compliance Elements
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 7 of 13
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
R2
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 8 of 13
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Lower
Long-term
Planning
R4
N/A
N/A
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Lower
Long-term
Planning
R3
FAC-001-3 — Facility Interconnection Requirements
The Generator Owner
failed to address two
parts of Requirement
R4 Part 4.1 through
Part 4.3.
The applicable
Generator Owner
addressed either R4,
Part 4.1 or Part 4.2 in
its Facility
interconnection
requirements, but did
not address both.
N/A
The Transmission
Owner addressed
either R3, Part 3.1 or
Part 3.2 in its Facility
interconnection
requirements, but did
not address both.
N/A
The Generator Owner
failed to address one
part of Requirement
R4 Part 4.1 through
Part 4.3.
The Transmission
Owner failed to
address two parts of
Requirement R3 Part
3.1 through Part 3.3.
The Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
Page 9 of 13
The applicable
Generator Owner
addressed neither R4,
Part 4.1 nor Part 4.2 in
its Facility
interconnection
requirements.
The Generator Owner
failed to address
Requirement R4 Part
4.1 through Part 4.3.
The Transmission
Owner addressed
neither R3, Part 3.1 nor
Part 3.2 in its Facility
interconnection
requirements.
The Transmission
Owner failed to
address Requirement
R3 Part 3.1 through
Part 3.3.
N/A
Medium N/A
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
Long-term
Planning
R7
N/A
N/A
Medium
Long-term
Planning
R6
N/A
Medium
Long-term
Planning
R5
N/A
FAC-001-3 — Facility Interconnection Requirements
N/A
N/A
N/A
Page 10 of 13
The Transmission
Operator with
Transmission Facilities
operating in an
Interconnection failed
to ensure that those
Transmission Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The Generation
Operator with
generation Facilities
operating in an
Interconnection failed
to ensure that those
generation Facilities
were included within
metered boundaries of
a Balancing Authority
Area.
The Load-Serving
Entity with Load
operating in an
Interconnection failed
to ensure that those
Loads were included
within metered
boundaries of a
Balancing Authority
Area.
Draft#21ofStandardFACͲ001Ͳ3:OctoberJuly,2015
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
FAC-001-3 — Facility Interconnection Requirements
Page 11 of 13
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 12 of 13
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 13 of 13
Implementation Plan
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Reliability Standard BAL-005-1
Requested Approval
x
BAL-005-1 – Balancing Authority Controls
Requested Retirement
x
BAL-005-0.2b – Automatic Generation Control
Prerequisite Approval
x
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers
across all Tie Lines, including PseudoǦTies, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (IME): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (IATEC): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of IATEC shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
x Lmax is the maximum value allowed for IATEC set by each BA between 0.2*|Bi| and
L10, 0.2*|Bi| Lmax L10 .
x
x
x
x
x
x
x
x
x
x
x
x
L10 ൌ ͳǤͷ כȜଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ .
H10 is a constant derived from the targeted frequency bound. It is the targeted rootmean-square (RMS) value of ten-minute average frequency error based on
frequency performance over a given year. The bound, Ȝ 10, is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - Bi * ƩTE/6)
IIactual is the hourly Inadvertent Interchange for the last hour.
ƩTE is the hourly change in system Time Error as distributed by the Interconnection
time monitor,where: ƩTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)
TDadj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TEoffset is 0.000 or +0.020 or -0.020.
PIIaccum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
BALͲ005Ͳ1–BalancingAuthorityControl
October2015
2
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME + IATEC
Where:
x NIA
=
Actual Net Interchange.
x
NIS
=
Scheduled Net Interchange.
x
B
=
Frequency Bias Setting.
x
FA
=
Actual Frequency.
x
FS
=
Scheduled Frequency.
x
IME
=
Interchange Meter Error.
x
IATEC
=
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie-line Bias (TLB)
Control and require the use of an ACE equation similar to the Reporting ACE
defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAAs on an Interconnection and is(are) consistent with
the following four principles of Tie Line Bias control will provide a valid alternative
to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency FS for all BAAs at all times; and,
BALͲ005Ͳ1–BalancingAuthorityControl
October2015
3
4. Excludes metering or computational errors. (The inclusion and use of the IME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC):A process designed and used to adjust a
Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in
that of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’Reporting ACEequation(oralternatecontrolprocesses).
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourcebalancewithinaBalancingAuthorityArea,andsupports
Interconnectionfrequencyinrealtime.
Applicable Entities
x
Balancing Authority
Applicable Facilities
x
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
BALͲ005Ͳ1–BalancingAuthorityControl
October2015
4
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented immediately after BAL-005-1 becomes effective as
reflected in the Implementation Plan for FAC-001-3, and BAL-006-2 will be retired concurrently
with the effective date for BAL-005-1 . Finally, to ensure proper coordination with BAL-001-2,
approved by the Commission in Order No. 810 issued on April 16, 2015, the following
definitions associated with BAL-005-1 will be implemented concurrently with the effective date
for BAL-001-2:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
Effective Dates
Definitions
The definitions of the following terms shall become effective immediately after the
effective date of BAL-001-21:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
BAL-005-1
Where approval by an applicable governmental authority is required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
Because the definition of “Reporting ACE” associated with BAL-005-1 will become effective immediately after the
effective date of BAL-001-2, the definition of “Reporting ACE” that was approved by the Commission on April 16,
2015 in Order No. 810 (151 FERC ¶ 61,048) will never go into effect.
1
BALͲ005Ͳ1–BalancingAuthorityControl
October2015
5
after the effective date of the applicable governmental authorities order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
after the date the standard is adopted by the NERC Board of Trustees’, or as otherwise
provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Automatic Generation Control, Pseudo Tie and Balancing Authority
shall be retired at midnight of the day immediately prior to the effective date of BAL-005-1, in
the jurisdiction in which the new standard is becoming effective.
The existing definitions of Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Meter Error, and Automatic Time Error Correction
shall be retired immediately after the effective date of BAL-001-2.2
Note that the definition of Reporting ACE that was approved by the Commission in Order No. 810, which will
replace the existing definition of Reporting ACE, will be retired immediately prior to the effective date for the
revised definition of Reporting ACE, as described above. As such, the definition of Reporting ACE approved by the
Commission in Order No. 810 will never go into effect.
2
BALͲ005Ͳ1–BalancingAuthorityControl
October2015
6
Implementation Plan
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Reliability Standard BAL-005-1
Requested Approval
x
BAL-005-1 – Balancing Authority Controls
Requested Retirement
x
BAL-005-0.2b – Automatic Generation Control
Prerequisite Approval
x
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers
across all Tie Lines, including PseudoǦTies, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (IME): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (IATEC): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of IATEC shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
x Lmax is the maximum value allowed for IATEC set by each BA between 0.2*|Bi| and
L10, 0.2*|Bi| Lmax L10 .
x
x
x
x
x
x
x
x
x
x
x
x
L10 ൌ ͳǤͷ כȜଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ .
H10Ȝ 兟10 is a constant derived from the targeted frequency bound. It is the
targeted root-mean-square (RMS) value of ten-minute average frequency error
based on frequency performance over a given year. The bound, Ȝ 兟10, is the same
for every Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - Bi * ƩTE/6)
IIactual is the hourly Inadvertent Interchange for the last hour.
ƩTE is the hourly change in system Time Error as distributed by the Interconnection
time monitor,where: ƩTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)
TDadj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TEoffset is 0.000 or +0.020 or -0.020.
PIIaccum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
BALͲ005Ͳ1–BalancingAuthorityControl
OctoberJuly2015
2
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME + IATEC
Where:
x NIA
=
Actual Net Interchange.
x
NIS
=
Scheduled Net Interchange.
x
B
=
Frequency Bias Setting.
x
FA
=
Actual Frequency.
x
FS
=
Scheduled Frequency.
x
IME
=
Interchange Meter Error.
x
IATEC
=
Automatic Time Error Correction.
All NERC Interconnections with multiple Balancing Authority Areas operate using
the principles of Tie-line Bias (TLB) Control and require the use of an ACE
equation similar to the Reporting ACE defined above. Any modification(s) to this
specified Reporting ACE equation that is(are) implemented for all BAAs on an
Interconnection and is(are) consistent with the following four principles of Tie
Line Bias control will provide a valid alternative to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency FS for all BAAs at all times; and,
BALͲ005Ͳ1–BalancingAuthorityControl
OctoberJuly2015
3
4. Excludes metering or computational errors. (The inclusion and use of the IME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC):A process designed and used to adjust a
Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in
that of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards. Centrally located equipment Equipment that automatically adjusts
resources generation in a Balancing Authority Area from a central location to help
maintain the Reporting ACE of a Balancing Authority’s Area within the bounds required
under the NERC Reliability Standardsinterchange schedule plus Frequency Bias. AGC
may also accommodate automatic inadvertent payback and time error correction.
Resources utilized under AGC may include, but not be limited to, conventional
generation, variable energy resources, storage devices and loads acting as resources,
such as Demand Response.
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’controlReporting ACEequation(oralternatecontrolprocesses).
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourceload-interchange-generationbalancewithinaBalancing
AuthorityArea,andsupportsInterconnectionfrequencyinrealtime.
Applicable Entities
x
Balancing Authority
Applicable Facilities
x
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
BALͲ005Ͳ1–BalancingAuthorityControl
OctoberJuly2015
4
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-005-1 will implemented concurrently with FAC-001-3 will be implemented
immediately after BAL-005-1 becomes effective, as reflected in the Implementation Plan for
FAC-001-3, and BAL-006-2 will be retired concurrently with the effective date for BAL-005-1
“Prerequisite Approvals” section above. Finally, to ensure proper coordination with BAL-001-2,
approved by the Commission in Order No. 810 issued on April 16, 2015, the following
definitions associated with BAL-005-1 will be implemented concurrently with the effective date
for BAL-001-2:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
Effective Dates
Definitions
The definitions of the following terms shall become effective immediately after the
effective date of BAL-001-21:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
Because the definition of “Reporting ACE” associated with BAL-005-1 will become effective immediately after the
effective date of BAL-001-2, the definition of “Reporting ACE” that was approved by the Commission on April 16,
2015 in Order No. 810 (151 FERC ¶ 61,048) will never go into effect.
1
BALͲ005Ͳ1–BalancingAuthorityControl
OctoberJuly2015
5
x
Automatic Time Error Correction
BAL-005-1
Where approval by an applicable governmental authority is required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
after the effective date of the that this standard is approved by applicable governmental
regulatory authorities order approving the standard, or as otherwise provided for in a
jurisdiction where approval by the an applicable governmental authority is required for a
standard to go into effect.
Where approval by an applicable governmental authority is not required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
the standard shall become effective on the first day of the first calendar quarter that is
twelve months after the date the standard is adopted by the NERC Board of Trustees’, or
as otherwise provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Reporting ACE and Automatic Generation Control, Pseudo Tie and
Balancing Authority shall should be retired at midnight of the day immediately prior to the
effective date of BAL-005-1, in the jurisdiction in which the new standard is becoming
effective.
The existing definitions of Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Meter Error, and Automatic Time Error Correction
shall be retired immediately after the effective date of BAL-001-2.2
Note that the definition of Reporting ACE that was approved by the Commission in Order No. 810, which will
replace the existing definition of Reporting ACE, will be retired immediately prior to the effective date for the
revised definition of Reporting ACE, as described above. As such, the definition of Reporting ACE approved by the
Commission in Order No. 810 will never go into effect.
2
BALͲ005Ͳ1–BalancingAuthorityControl
OctoberJuly2015
6
Implementation Plan
Reliability Standard BAL-006-2
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
N/A
Requested Retirement
x
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Prerequisite Events
x NERC Operating Committee approval of Inadvertent Interchange Guideline1
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-2 will be retired concurrently with the effective date of BAL-005-1 and requisite
approval of Inadvertent Interchange Guideline, as reflected in the “Prerequisite Approvals” and
“Prerequisite Events” sections above.
Effective Dates
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.
1
BAL-006-2 shall be retired on the effective date of BAL-005-1 and the approval of Inadvertent
Interchange Guideline.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
November2015
2
Implementation Plan
Reliability Standard BAL-006-23
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
N/ABAL-006-3 – Inadvertent Interchange
Requested Retirement
x
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Prerequisite Events
x NERC Operating Committee approval of Inadvertent Interchange Guideline1
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-23 will be retiredimplemented concurrently with the effective date of BAL-0051 and requisite approval of Inadvertent Interchange Guideline, as reflected in the “Prerequisite
Approvals” and “Prerequisite Events” sections above.
Effective Dates
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.
1
BAL-006-23 shall become effective retired on the effective date of BAL-005-1 and the approval
of Inadvertent Interchange Guideline.
Retirements
BAL-006-2 (Inadvertent Interchange) shall be retired immediately prior to the Effective Date of
BAL-006-3 (Inadvertent Interchange) in the particular jurisdiction in which the revised
standard is becoming effective.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
NovemberJuly2015
2
Implementation Plan
Reliability Standard FAC-001-3
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
FAC-001-3 – Facility Interconnection Requirements
Requested Retirement
x
FAC-001-2 – Facility Interconnection Requirements
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
Background
Reliability Standard FAC-001-3 addresses Facility Interconnection Requirements, which ensure
the avoidance of adverse impacts on the reliability of the Bulk Electric System by requiring
Transmission Owners and applicable Generator Owners to document and make Facility
interconnection requirements available so that entities seeking to interconnect will have
necessary information. Reliability Standard FAC-001-3 and associated Implementation Plan was
developed in conjunction with BAL-005-1 (Balancing Authority Controls) to ensure that entities
with facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented concurrently with BAL-005-1, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
FAC-001-3 shall become effective on the effective date of BAL-005-1.
Retirements
FAC-001-2 (Facility Interconnection Requirements) shall be retired immediately prior to the
Effective Date of FAC-001-3 (Facility Interconnection Requirements) in the particular
jurisdiction in which the revised standard is becoming effective.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
November2015
2
Unofficial Comment Form
Project 2010-14.2.1 Balancing Authority Reliability-based
Controls
Do not use this form for submitting comments. Use the electronic form to submit comments on the draft
standards BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility Interconnection
Requirements, and the recommended retirement of BAL-006-2 – Inadvertent Interchange. The electronic
form must be submitted by 8 p.m. Eastern, Monday, January 11, 2016.
m. Eastern, Thursday, August 20, 2015
Documents and information about this project are available on the project page. If you have questions,
contact Senior Standards Developer, Darrel Richardson (via email) or at (609) 613-1848.
Background Information
On September 19, 2013, the NERC Standards Committee appointed ten subject matter experts to serve on
the BARC 2 periodic review team (BARC 2 PRT). 1 As part of its review, the BARC 2 PRT used background
information on the standards and the questions set forth in the Periodic Review Template developed by
NERC and approved by the Standards Committee, along with associated worksheets and reference
documents, to determine whether BAL-005-0.2b and BAL-006-2 should be: (1) affirmed as is (i.e., no
changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3)
withdrawn. The recommendations of the BARC 2 PRT are in the Periodic Review Templates and SAR.
The Standards Committee approved a revised SAR that was posted for a 30-day comment period from July
16, 2014 through August 14, 2014. The BARC Phase 2.1 standard drafting team (BARC 2.1 SDT) reviewed
the comments received from the SAR posting and developed revisions to BAL-005-0.2b, BAL-006-2 and
FAC-001-2 standards. The standard were posted for a 45-day comment period and initial ballot from July
30, 2015 through September 14, 2015. The BARC 2.1 SDT also issued a survey to the industry to gather
additional information concerning the disposition of the remaining requirements in BAL-006-2. Based on
industry comments the BARC 2.1 SDT is proposing additional modifications to the definition of Automatic
Generation Control (AGC) and Pseudo Tie, as well as additional modifications to BAL-005 and FAC-001 and
retirement of the remaining requirements of BAL-006. With the retirement of the BAL-006 standard the
BARC 2.1 SDT is also proposing to develop a Inadvertent Interchange Guideline.
This project addresses directives from FERC Order 693, and provides additional clarity to many
requirements, as well as retiring requirements that meet the criteria developed in the Paragraph 81
project.
1
The Standards Committee subsequently appointed an eleventh SME to the BARC 2 PRT.
Questions
1. The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the
proposed modifications provide sufficient clarity? If not, please explain in the comment area
below.
Yes
No
Comments:
2. If you are not in support of the proposed modifications to BAL-005-1, please provide your
objection(s) and proposed solution(s) in the area below.
Comments:
3. If you are not in support of the retirement of BAL-006-2 and the development of a guideline,
please provide your objection(s) and proposed solution(s) in the area below.
Comments:
4. If you are not in support of the proposed modifications to FAC-001-3, please provide your
objection(s) and proposed solution(s) in the area below.
Comments:
Unofficial Comment Form
Project 2010-14.2.1 BARC | November 2015 – January 2016
2
BALͲ005Ͳ0.2bR5
BALͲ005Ͳ0.2bR4
BALͲ005Ͳ0.2bR3
BALͲ005Ͳ0.2bR2
BALͲ005Ͳ1R1
Requirementin
ApprovedStandard
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
RequirementsR1PartsR1.1andR1.2donotprovidefornecessary
RequirementR1PartR1.1andPartR1.2
informationconcerningthecalculationofReportingACE.The
havebeen movedintoFACͲ001Ͳ2
requirementprovidesforinformationnecessarywhenconnectingto
RequirementR3andR4.RequirementR1
theelectricsystem.
PartR1.3isbeingretired.
RequirementR1Part1.3isbeingretiredinconjunctionwiththeRiskͲ
basedRegistrationinitiativedeͲcertifyingtheLSEfunction.
ThisrequirementwasretiredaspartoftheoriginalParagraph81
Retired
project.ItsretirementwasapprovedbyFERCeffectiveJanuary21,
2014.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR7.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR7.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR7.
Transition of BAL-005-0.2b to BAL-005-1
Project 2010-14.2.1 Mapping Document
BALͲ005Ͳ0.2bR9
BALͲ005Ͳ0.2bR8
BALͲ005Ͳ0.2bR7
BALͲ005Ͳ0.2bR6
Requirementin
ApprovedStandard
2
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
TheportionoftherequirementconcerningcalculatingACEwasmoved
MovedtodefinitionofReportingACEand
intothedefinitionforReportingACE.Theportionoftherequirement
RequirementR2
concerninganentity’sinabilitytocalculateAceformorethan30
minuteswasmovedintoRequirementR2.
ThisrequirementshouldberetiredunderParagraph81criteria.The
firstsentencecovershavingafunctionalEMSorothersystemcapable
ofcalculatingReportingACEandcontrollingresources,though
Retire
resourcescanbedispatchedmanuallywithoutanydetrimentto
reliability.TheSDTbelievesthattheterm“operateAGC”inR7refersto
thecapabilitytocontinuouslycalculateACE,notautomaticcontrolof
resourcestotheextentBAscannottakeresourcesoff“AGC”mode.
Thebodyofthisrequirementwasmovedto
ThebodyofthisrequirementhasbeenmovedtoRequirementR1and
RequirementR1andPart8.1wasmoved
Part8.1hasbeenmovedintoRequirementR3.
intoRequirementR3
R9iscoveredinthedefinitionofReportingACE,andtheproposedR7
ensuresthattheBAdoesnotincludeanyInterchangeinitsReporting
ACEthatdoesnothaveanAdjacentBA.
RegardingR9.1,theActualNetInterchangeandScheduledNet
InterchangevaluesintheReportingACEcalculationincludeprovisions
Retire
fortheBalancingAuthoritytoincludeitshighvoltagedirect(HVDC)link
toanotherasynchronousinterconnection.Byassuringthevaluesare
handledconsistentlyintheactualandscheduledInterchangeterms
includedintherealͲtimeReportingACEbydefinition,theBalancing
Authorityisnotbeinginstructed“how”toimplementtheHVDClink,
butallowedtodecidethemethoditwilluse.
BALͲ005Ͳ0.2bR16
BALͲ005Ͳ0.2bR15
BALͲ005Ͳ0.2bR14
BALͲ005Ͳ0.2bR13
BALͲ005Ͳ0.2bR12
BALͲ005Ͳ0.2bR11
BALͲ005Ͳ0.2bR10
Requirementin
ApprovedStandard
3
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
MovedtoRequirementR7
ThisrequirementhasbeenmovedtoRequirementR7.
Theportionoftherequirementconcerningcommontime
synchronizationwasmovedintoRequirementR7.Theportionofthe
MovedtoRequirementR7
requirementconcerninganequipmenterrorwasmovedinto
RequirementR7.
MovedtoRequirementR4andRequirement ThisrequirementhasbeenmovedintoRequirementR4and
R7
RequirementR7.
ThisrequirementisduplicativeoftheintentofEOPͲ008ͲLoss
ofControlRoomFunctionality.Inaddition,proposedR3
Retired
requiresaperformancelevelthattheBalancingAuthority
Areamustmeet.ThestandarddoesnottelltheBAAhowto
meetit.
MovedtoRequirementR4
ThisrequirementhasbeenmovedintoRequirementR4.
BALͲ005Ͳ0.2bR17
Requirementin
ApprovedStandard
4
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
ThisrequirementwhichaddressaccuracyofRTUandtransducersis
meaninglessintoday’sworld.RTUsdonotquantizemeasurement
anymore,thesearedonebyrelayormeters.Transducersarenotused
anymoreandhavebeenreplacedbymetersandrelayswhichmeasure
quantities.Thisrequirementshouldberestoredsuchthatitactually
supportsanaccuratecalculationofACEandproperoperationofAGC
Partiallyretired(partiallycapturedinnew
byspecifyingaccuracyrequirementsforalltelemetryassociatedwith
RequirementR3)
ACE(Frequency,MWandtheassociatedsensingdevicesand
telemetry).Inaddition,theinterpretationeffective8/27/2008inBALͲ
005Ͳ0.2.bforR17statesthatthisrequirementisspecifictothe
equipmentusedtodeterminethefrequencycomponentrequiredfor
reportingACE.ThisisnowbeingcapturedinRequirementR3.
BALͲ005Ͳ0.2bR4
BALͲ005Ͳ0.2bR3
BALͲ005Ͳ0.2bR2
BALͲ005Ͳ1R1
Requirementin
ApprovedStandard
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
ThisrRequirementsR1PartsR1.1andR1.2doesnotprovidefor
ThisRequirementR1PartR1.1andPartR1.2 necessaryinformationconcerningthecalculationofReportingACE.
havehasbeen movedintoFACͲ001Ͳ2
Therequirementprovidesforinformationnecessarywhenconnecting
RequirementR35and,R46.andR7
totheelectricsystem.
RequirementR1PartR1.3isbeingretired.
RequirementR1Part1.3isbeingretiredinconjunctionwiththeRiskͲ
basedRegistrationinitiativedeͲcertifyingtheLSEfunction.
ThisrequirementwasretiredaspartoftheoriginalParagraph81
Retired
project.ItsretirementwasapprovedbyFERCeffectiveJanuary21,
2014.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR71and
RequirementR8.
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR71and
RequirementR8.
Transition of BAL-005-0.2b to BAL-005-1
Project 2010-14.2.1 Mapping Document
BALͲ005Ͳ0.2bR8
BALͲ005Ͳ0.2bR7
BALͲ005Ͳ0.2bR6
BALͲ005Ͳ0.2bR5
Requirementin
ApprovedStandard
2
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Thisrequirementcanberetiredsincecoordinationofcommonvalues
Retire
betweenAdjacentBAsiscoveredintheRequirementR71and
RequirementR8.
TheportionoftherequirementconcerningcalculatingACEwasmoved
MovedtodefinitionofReportingACEand
intothedefinitionforReportingACE.Theportionoftherequirement
RequirementR23
concerninganentity’sinabilitytocalculateAceformorethan30
minuteswasmovedintoRequirementR23.
ThisrequirementshouldberetiredunderParagraph81criteria.The
firstsentencecovershavingafunctionalEMSorothersystemcapable
ofcalculatingReportingACEandcontrollingresources,though
Retire
resourcescanbedispatchedmanuallywithoutanydetrimentto
reliability.TheSDTbelievesthattheterm“operateAGC”inR7refersto
thecapabilitytocontinuouslycalculateACE,notautomaticcontrolof
resourcestotheextentBAscannottakeresourcesoff“AGC”mode.
Thebodyofthisrequirementwasmovedto
ThebodyofthisrequirementhasbeenmovedtoRequirementR12and
RequirementR12andPart8.1wasmoved
Part8.1hasbeenmovedintoRequirementR34.
intoRequirementR34
BALͲ005Ͳ0.2bR14
BALͲ005Ͳ0.2bR13
BALͲ005Ͳ0.2bR12
BALͲ005Ͳ0.2bR11
BALͲ005Ͳ0.2bR10
BALͲ005Ͳ0.2bR9
Requirementin
ApprovedStandard
3
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
R9iscoveredinthedefinitionofReportingACE,andtheproposedR71
ensuresthattheBAdoesnotincludeanyInterchangeinitsReporting
ACEthatdoesnothaveanAdjacentBA.
RegardingR9.1,theActualNetInterchangeandScheduledNet
InterchangevaluesintheReportingACEcalculationincludeprovisions
Retire
fortheBalancingAuthoritytoincludeitshighvoltagedirect(HVDC)link
toanotherasynchronousinterconnection.Byassuringthevaluesare
handledconsistentlyintheactualandscheduledInterchangeterms
includedintherealͲtimeReportingACEbydefinition,theBalancing
Authorityisnotbeinginstructed“how”toimplementtheHVDClink,
butallowedtodecidethemethoditwilluse.
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
Thebasicsofthisrequirementisfactoredintothedefinitionof
Retire
ScheduledNetInterchange(NIS)usedintheReportingACEcalculation
asdefinedintheNERCGlossary.
MovedtoRequirementR71
ThisrequirementhasbeenmovedtoRequirementR71.
Theportionoftherequirementconcerningcommontime
MovedtoRequirementR1andRequirement synchronizationwasmovedintoRequirementR71.Theportionofthe
R7
requirementconcerninganequipmenterrorwasmovedinto
RequirementR7.
MovedtoRequirementR45and
ThisrequirementhasbeenmovedintoRequirementR45and
RequirementR78
RequirementR78.
BALͲ005Ͳ0.2bR17
BALͲ005Ͳ0.2bR16
BALͲ005Ͳ0.2bR15
Requirementin
ApprovedStandard
4
Standard:BALͲ005Ͳ1–DisturbanceControlStandard
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
ThisrequirementisduplicativeoftheintentofEOPͲ008ͲLoss
ofControlRoomFunctionality.Inaddition,proposedR3
Retired
requiresaperformancelevelthattheBalancingAuthority
Areamustmeet.ThestandarddoesnottelltheBAAhowto
meetit.
MovedtoRequirementR45
ThisrequirementhasbeenmovedintoRequirementR45.
ThisrequirementwhichaddressaccuracyofRTUandtransducersis
meaninglessintoday’sworld.RTUsdonotquantizemeasurement
anymore,thesearedonebyrelayormeters.Transducersarenotused
anymoreandhavebeenreplacedbymetersandrelayswhichmeasure
quantities.Thisrequirementshouldberestoredsuchthatitactually
supportsanaccuratecalculationofACEandproperoperationofAGC
Partiallyretired(partiallycapturedinnew
byspecifyingaccuracyrequirementsforalltelemetryassociatedwith
RequirementR34)
ACE(Frequency,MWandtheassociatedsensingdevicesand
telemetry).Inaddition,theinterpretationeffective8/27/2008inBALͲ
005Ͳ0.2.bforR17statesthatthisrequirementisspecifictothe
equipmentusedtodeterminethefrequencycomponentrequiredfor
reportingACE.ThisisnowbeingcapturedinRequirementR34.
BALͲ006Ͳ2R5
BALͲ006Ͳ2R4
BALͲ006Ͳ2R3
BALͲ006Ͳ2R2
BALͲ006Ͳ2R1
Requirementin
ApprovedStandard
Standard:BALͲ006Ͳ2–InadvertentInterchange
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
Retired
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
Retired
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.
Thisrequirementdirectlyimpactstheabilitytocalculateanaccurate
MovedtoBALͲ005Ͳ1RequirementR7
ReportingACEvalue.
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
Retired
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
Retired
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.
Transition of BAL-006-2
Project 2010-14.2.1 Mapping Document
Requirementin
ApprovedStandard
Standard:BALͲ006Ͳ2–InadvertentInterchange
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
2
BALͲ006Ͳ2R4
BALͲ006Ͳ2R3
BALͲ006Ͳ2R2
BALͲ006Ͳ2R1
Requirementin
ApprovedStandard
Standard:BALͲ006Ͳ23–InadvertentInterchange
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
RetiredNochange
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.Nochange
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
RetiredNochange
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.Nochange
MovedtoBALͲ005Ͳ1RequirementR71and Thisrequirementdirectlyimpactstheabilitytocalculateanaccurate
RequirementR8
ReportingACEvalue.
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
RetiredNochange
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.Nochange
Transition of BAL-006-2 to BAL-006-3
Project 2010-14.2.1 Mapping Document
BALͲ006Ͳ2R5
Requirementin
ApprovedStandard
Standard:BALͲ006Ͳ23–InadvertentInterchange
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
TheSDTisrecommendingthisrequirementberetired.This
requirementiscompletelyadministrativeinnature.Itmeetsthe
RetiredNochange
Paragraph81criteriaandisinagreementwiththeIndependent
Expertsreviewfindings.Nochange
2
BALͲ005Ͳ0.2bR1
BALͲ005Ͳ0.2bR1
Requirementin
ApprovedStandard
FACͲ001Ͳ2R1
FACͲ001Ͳ2R2
FACͲ001Ͳ2R3
FACͲ001Ͳ2R4
Standard:FACͲ001Ͳ3–FacilityInterconnectionRequirements
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R3Part3.3
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R4Part4.3
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
Transition of FAC-001-2 to FAC-001-3
Project 2010-14.2.1 Mapping Document
BALͲ005Ͳ0.2bR1
BALͲ005Ͳ0.2bR1
BALͲ005Ͳ0.2bR1
Requirementin
ApprovedStandard
FACͲ001Ͳ2R1
FACͲ001Ͳ2R2
FACͲ001Ͳ2R3
FACͲ001Ͳ2R4
Standard:FACͲ001Ͳ3–FacilityInterconnectionRequirements
TransitionstothebelowRequirementin
DescriptionandChangeJustification
NewStandardorOtherAction
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
Nochange
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R35Part3.3
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R46Part4.3
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
ThisrequirementwasmovedfromBALͲ005Ͳ0.2bsinceitdoesnot
MovedfromBALͲ005Ͳ0.2bRequirementR1 provideforinformationregardingthecalculationofReportingACE.
toFACͲ001Ͳ3R7
Therequirementismoreinlinewithfacilitiesattachingtoan
interconnection.
Transition of FAC-001-2 to FAC-001-3
Project 2010-14.2.1 Mapping Document
Violation Risk Factor and Violation Severity
Level Assignments
Project 2010-14.2.1 Balancing Authority Reliability-based
Controls
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinBALͲ005Ͳ1,BalancingAuthorityControl.
EachprimaryrequirementisassignedaVRFandasetofoneormoreVSLs.Theseelementssupportthe
determinationofaninitialvaluerangeforthebasepenaltyamountregardingviolationsof
requirementsinFERCͲapprovedreliabilitystandards,asdefinedintheEROSanctionGuidelines.
Justification for Assignment of Violation Risk Factors
TheFrequencyResponseStandarddraftingteamappliedthefollowingNERCcriteriawhenproposing
VRFsfortherequirementsunderthisproject:
High Risk Requirement
Arequirementthat,ifviolated,coulddirectlycauseorcontributetobulkelectricsysteminstability,
separation,oracascadingsequenceoffailures,orcouldplacethebulkelectricsystematan
unacceptableriskofinstability,separation,orcascadingfailures;orarequirementinaplanningtime
framethat,ifviolated,could,underemergency,abnormal,orrestorativeconditionsanticipatedbythe
preparations,directlycauseorcontributetoBulkElectricSysteminstability,separation,oracascading
sequenceoffailures,orcouldplacetheBulkElectricSystematanunacceptableriskofinstability,
separation,orcascadingfailures,orcouldhinderrestorationtoanormalcondition.
Medium Risk Requirement
Arequirementthat,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem.However,
violationofamediumͲriskrequirementisunlikelytoleadtoBulkElectricSysteminstability,separation,
orcascadingfailures;orarequirementinaplanningtimeframethat,ifviolated,could,under
emergency,abnormal,orrestorativeconditionsanticipatedbythepreparations,directlyandadversely
affecttheelectricalstateorcapabilityofthebulkelectricsystem,ortheabilitytoeffectivelymonitor,
control,orrestorethebulkelectricsystem.However,violationofamediumͲriskrequirementis
unlikely,underemergency,abnormal,orrestorationconditionsanticipatedbythepreparationstolead
toBulkElectricSysteminstability,separation,orcascadingfailures,nortohinderrestorationtoa
normalcondition.
BALͲ005Ͳ1
VRFandVSLAssignments–November,
2015
1
Lower Risk Requirement
Arequirementthatisadministrativeinnature,andarequirementthat,ifviolated,wouldnotbe
expectedtoadverselyaffecttheelectricalstateorcapabilityoftheBulkElectricSystem,ortheabilityto
effectivelymonitorandcontroltheBulkElectricSystem;orarequirementthatisadministrativein
natureandarequirementinaplanningtimeframethat,ifviolated,wouldnot,undertheemergency,
abnormal,orrestorativeconditionsanticipatedbythepreparations,beexpectedtoadverselyaffectthe
electricalstateorcapabilityoftheBulkElectricSystem,ortheabilitytoeffectivelymonitor,control,or
restoretheBulkElectricSystem.Aplanningrequirementthatisadministrativeinnature.
TheSDTalsoconsideredconsistencywiththeFERCViolationRiskFactorGuidelinesforsettingVRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
ThecommissionseekstoensurethatViolationRiskFactorsassignedtorequirementsofreliability
standardsintheseidentifiedareasappropriatelyreflecttheirhistoricalcriticalimpactonthereliability
oftheBulkPowerSystem.
IntheVSLOrder,FERClistedcriticalareas(fromtheFinalBlackoutReport)whereviolationscould
severelyaffectthereliabilityoftheBulkPowerSystem:2
x Emergencyoperations
x Vegetationmanagement
x Operatorpersonneltraining
x Protectionsystemsandtheircoordination
x Operatingtoolsandbackupfacilities
x Reactivepowerandvoltagecontrol
x Systemmodelinganddataexchange
x Communicationprotocolandfacilities
x Requirementstodetermineequipmentratings
x Synchronizeddatarecorders
x Clearercriteriaforoperationallycriticalfacilities
x Appropriateuseoftransmissionloadingrelief
Guideline (2) — Consistency within a Reliability Standard
ThecommissionexpectsarationalconnectionbetweenthesubͲrequirementViolationRiskFactor
assignmentsandthemainrequirementViolationRiskFactorassignment.
Guideline (3) — Consistency among Reliability Standards
1
NorthAmericanElectricReliabilityCorp.,119FERC¶61,145,orderonreh’gandcompliancefiling,120FERC¶61,145
(2007)(“VRFRehearingOrder”).
2
Id.atfootnote15.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
2
ThecommissionexpectstheassignmentofViolationRiskFactorscorrespondingtorequirementsthat
addresssimilarreliabilitygoalsindifferentreliabilitystandardswouldbetreatedcomparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
WhereasinglerequirementcoͲminglesahigherriskreliabilityobjectiveandalesserriskreliability
objective,theVRFassignmentforsuchrequirementmustnotbewatereddowntoreflectthelowerrisk
levelassociatedwiththelessimportantobjectiveofthereliabilitystandard.
ThefollowingdiscussionaddresseshowtheSDTconsideredFERC’sVRFGuidelines2through5.The
teamdidnotaddressGuideline1directlybecauseofanapparentconflictbetweenGuidelines1and4.
WhereasGuideline1identifiesalistoftopicsthatencompassnearlyalltopicswithinNERC’sreliability
standardsandimpliesthattheserequirementsshouldbeassigneda“High”VRF,Guideline4directs
assignmentofVRFsbasedontheimpactofaspecificrequirementtothereliabilityofthesystem.The
SDTbelievesthatGuideline4isreflectiveoftheintentofVRFsinthefirstinstance;and,therefore,
concentrateditsapproachonthereliabilityimpactoftherequirements.
VRF for BAL-005-1:
TherearesevenrequirementsinBALͲ005Ͳ1.Alloftherequirementswereassigneda“Medium”VRF.
VRF for BAL-005-1, Requirement R1:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ005Ͳ1areassigneda“Medium”VRF.
RequirementR1issimilarinscopetoRequirementR3andRequirementR5.Thisisalso
consistentwiththecurrentFERCapprovedVRFforBALͲ005Ͳ0.2bRequirementR8.
•
FERCGuideline3—Consistencyamongreliabilitystandardsexists.Thisrequirementis
identicaltothecurrentenforceableBALͲ005Ͳ0.2bStandardRequirementR8whichhasan
approvedMediumVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
3
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for BAL-005-1, Requirement R2:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ005Ͳ1areassigneda“Medium”VRF.
ThisisalsoconsistentwiththecurrentFERCapprovedVRFforBALͲ005Ͳ0.2bRequirementR6.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementis
identicaltothecurrentenforceableBALͲ005Ͳ0.2bstandardRequirementR6whichhasan
approvedMediumVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for BAL-005-1, Requirement R3:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Alloftherequirementsin
BALͲ005Ͳ1areassigneda“Medium”VRF.ThisisalsoconsistentwiththecurrentFERC
approvedVRFinBALͲ005Ͳ0.2bRequirementR8.1.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ005Ͳ0.2bstandardRequirementR8.1whichhasan
approvedMediumVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
4
VRF for BAL-005-1, Requirement R4:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Thisrequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ005Ͳ1areassigneda“Medium”VRF.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ005Ͳ0.2bstandardRequirementR8.1whichhasan
approvedMediumVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for BAL-005-1, Requirement R5:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Thisrequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ005Ͳ1areassigneda“Medium”VRF.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttoBALͲ005Ͳ0.2bstandardRequirementR3whichhasaMediumVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for BAL-005-1, Requirement R6:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Thisrequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ005Ͳ1areassigneda“Medium”VRF.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttoBALͲ005Ͳ0.2bstandardRequirementR7whichhasaMediumVRF.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
5
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for BAL-005-1, Requirement R7:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Alloftherequirementsin
BALͲ005Ͳ1areassigneda“Medium”VRF.ThisisalsoconsistentwiththecurrentFERC
approvedVRFinBALͲ005Ͳ0.2bRequirementR12whichhasanapprovedMediumVRFandBALͲ
006Ͳ2RequirementR3whichhasaLowerVRF.However,theSDTfeltthatthisrequirement
wasnotpurelyanadministrativerequirementandthereforedeservedahigherVRF.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ005Ͳ0.2bRequirementR12whichhasanapproved
MediumVRFandBALͲ006Ͳ2RequirementR3whichhasanapprovedLowerVRF.However,the
SDTfeltthatthisrequirementwasnotpurelyanadministrativerequirementandtherefore
deservedahigherVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
6
Justification for Assignment of Violation Severity Levels:
IndevelopingtheVSLsforthestandardsunderthisproject,theSDTanticipatedtheevidencethatwould
bereviewedduringanaudit,anddevelopeditsVSLsbasedonthenoncomplianceanauditormayfind
duringatypicalaudit.TheSDTbaseditsassignmentofVSLsonthefollowingNERCcriteria:
Lower
Moderate
Missingaminor
Missingatleastone
element(orasmall
significantelement(or
percentage)ofthe
amoderate
requiredperformance. percentage)ofthe
requiredperformance.
Theperformanceor
productmeasuredhas Theperformanceor
significantvalue,asit productmeasuredstill
almostmeetsthefull hassignificantvaluein
intentofthe
meetingtheintentof
requirement.
therequirement.
High
Severe
Missingmorethanone
significantelement(or
ismissingahigh
percentage)ofthe
requiredperformance,
orismissingasingle
vitalcomponent.
Theperformanceor
producthaslimited
valueinmeetingthe
intentofthe
requirement.
Missingmostorallof
thesignificant
elements(ora
significantpercentage)
oftherequired
performance.
Theperformance
measureddoesnot
meettheintentofthe
requirement,orthe
productdelivered
cannotbeusedin
meetingtheintentof
therequirement.
FERC’sVSLGuidelinesarepresentedbelow,followedbyananalysisofwhethertheVSLsproposedfor
eachrequirementinBALͲ005Ͳ1meettheFERCGuidelinesforassessingVSLs:
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
7
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
ComparetheVSLstoanypriorlevelsofnoncomplianceandavoidsignificantchangesthatmay
encouragealowerlevelofcompliancethanwasrequiredwhenlevelsofnoncompliancewereused.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Aviolationofa“binary”typerequirementmustbea“Severe”VSL.
Donotuseambiguoustermssuchas“minor”and“significant”todescribenoncompliantperformance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLsshouldnotexpandonwhatisrequiredintherequirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
...unlessotherwisestatedintherequirement,eachinstanceofnoncompliancewitharequirementisa
separateviolation.Section4oftheSanctionGuidelinesstatesthatassessingpenaltiesonaperͲ
violationͲperͲdaybasisisthe“default”forpenaltycalculations.
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
8
TheNERCVSL
Guidelinesare
satisfied.The
requirementis
binaryandthe
performance
measureddoes
notmeetthe
intentofthe
requirement.
Asdrafted,the
proposedVSLsdonot
lowerthecurrentlevel
ofcompliance.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
ProposedVSLisbinaryand
thereforeonlyhasasevereVSL.
TheproposedVSLlanguagedoes
notincludeambiguousterms.
TheVSLissimilartothecurrent
approvedVSLforBALͲ005Ͳ0.2b
RequirementR8.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,
2015
R1
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R1:
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
9
ProposedVSLsare
basedonasingle
violationandnota
cumulativeviolation
methodology.
Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations
Guideline 4
TheNERCVSL TheproposedVSLsdonot
Guidelinesare lowerthecurrentlevelof
satisfiedby
compliance.
incorporating
levelsof
noncompliance
performance.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLsarenot
binary.ProposedVSL
languagedoesnotinclude
ambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,
2015
R2.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R2:
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
theamountoftimean
entityisnonͲcompliant
withtherequirement.
ProposedVSLsare
consistentwiththe
requirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
10
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL Asdrafted,theproposed
Guidelinesare VSLsdonotlowerthe
satisfiedby
currentlevelofcompliance.
incorporating
levelsof
noncompliance
performance.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLsarenot
binary.ProposedVSL
languagedoesnotinclude
ambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyontheamountof
timeanentityisnonͲ
compliantwiththe
requirement.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
R3.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R3:
11
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL Asdrafted,theproposed
Guidelinesare VSLsdonotlowerthe
satisfied.The currentlevelofcompliance.
requirementis
binaryandthe
performance
measureddoes
notmeetthe
intentofthe
requirement.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLisbinaryand
thereforeonlyhasasevere
VSL.ProposedVSLlanguage
doesnotincludeambiguous
termsandensures
uniformityandconsistency
inthedeterminationof
penaltiesbasedonlyon
whethertheinformation
wasprovided.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
R4.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R4:
12
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL Asdrafted,theproposed
Guidelinesare VSLsdonotlowerthe
satisfiedby
currentlevelofcompliance.
incorporating
levelsof
noncompliance
performance.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLsarenot
binary.ProposedVSL
languagedoesnotinclude
ambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyontheamountof
timeanentityisnonͲ
compliantwiththe
requirement.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
R5.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R5:
13
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL
Guidelinesare
satisfied.The
requirementis
binaryandthe
performance
measureddoes
notmeetthe
intentofthe
requirement.
Thisrequirementisnew.As
drafted,theproposedVSL
doesnotlowerthecurrent
levelofcompliance.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLisbinaryand
thereforeonlyhasasevere
VSL.ProposedVSLlanguage
doesnotincludeambiguous
termsandensures
uniformityandconsistency
inthedeterminationof
penaltiesbasedonlyon
whethertheentity
implementedanOperating
Processtoidentifyand
mitigateerrors.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
R6.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R6:
14
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL Asdrafted,theproposed
Guidelinesare VSLdoesnotlowerthe
satisfied.The currentlevelofcompliance.
requirementis
binaryandthe
performance
measureddoes
notmeetthe
intentofthe
requirement.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLisbinaryand
thereforeonlyhasasevere
VSL.ProposedVSLlanguage
doesnotincludeambiguous
termsandensures
uniformityandconsistency
inthedeterminationof
penalties.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
BALͲ005Ͳ1
VRFandVSLAssignments–November,2015
R7.
R#
Compliance with
NERC VSL
Guidelines
VSLs for BAL-005-1 Requirement R7:
15
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
Violation Risk Factor and Violation Severity
Level Assignments
Project 2010-14.2.1 Balancing Authority Reliability-based
Controls
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinFACͲ001Ͳ3,FacilityInterconnection
Requirements.EachprimaryrequirementisassignedaVRFandasetofoneormoreVSLs.These
elementssupportthedeterminationofaninitialvaluerangeforthebasepenaltyamountregarding
violationsofrequirementsinFERCͲapprovedreliabilitystandards,asdefinedintheEROSanction
Guidelines.
Justification for Assignment of Violation Risk Factors
TheFrequencyResponseStandarddraftingteamappliedthefollowingNERCcriteriawhenproposing
VRFsfortherequirementsunderthisproject:
High Risk Requirement
Arequirementthat,ifviolated,coulddirectlycauseorcontributetobulkelectricsysteminstability,
separation,oracascadingsequenceoffailures,orcouldplacethebulkelectricsystematan
unacceptableriskofinstability,separation,orcascadingfailures;orarequirementinaplanningtime
framethat,ifviolated,could,underemergency,abnormal,orrestorativeconditionsanticipatedbythe
preparations,directlycauseorcontributetoBulkElectricSysteminstability,separation,oracascading
sequenceoffailures,orcouldplacetheBulkElectricSystematanunacceptableriskofinstability,
separation,orcascadingfailures,orcouldhinderrestorationtoanormalcondition.
Medium Risk Requirement
Arequirementthat,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem.However,
violationofamediumͲriskrequirementisunlikelytoleadtoBulkElectricSysteminstability,separation,
orcascadingfailures;orarequirementinaplanningtimeframethat,ifviolated,could,under
emergency,abnormal,orrestorativeconditionsanticipatedbythepreparations,directlyandadversely
affecttheelectricalstateorcapabilityofthebulkelectricsystem,ortheabilitytoeffectivelymonitor,
control,orrestorethebulkelectricsystem.However,violationofamediumͲriskrequirementis
unlikely,underemergency,abnormal,orrestorationconditionsanticipatedbythepreparationstolead
FACͲ001Ͳ3
VRFandVSLAssignments–November,
2015
1
toBulkElectricSysteminstability,separation,orcascadingfailures,nortohinderrestorationtoa
normalcondition.
Lower Risk Requirement
Arequirementthatisadministrativeinnature,andarequirementthat,ifviolated,wouldnotbe
expectedtoadverselyaffecttheelectricalstateorcapabilityoftheBulkElectricSystem,ortheabilityto
effectivelymonitorandcontroltheBulkElectricSystem;orarequirementthatisadministrativein
natureandarequirementinaplanningtimeframethat,ifviolated,wouldnot,undertheemergency,
abnormal,orrestorativeconditionsanticipatedbythepreparations,beexpectedtoadverselyaffectthe
electricalstateorcapabilityoftheBulkElectricSystem,ortheabilitytoeffectivelymonitor,control,or
restoretheBulkElectricSystem.Aplanningrequirementthatisadministrativeinnature.
TheSDTalsoconsideredconsistencywiththeFERCViolationRiskFactorGuidelinesforsettingVRFs:1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
ThecommissionseekstoensurethatViolationRiskFactorsassignedtorequirementsofreliability
standardsintheseidentifiedareasappropriatelyreflecttheirhistoricalcriticalimpactonthereliability
oftheBulkPowerSystem.
IntheVSLOrder,FERClistedcriticalareas(fromtheFinalBlackoutReport)whereviolationscould
severelyaffectthereliabilityoftheBulkPowerSystem:2
x Emergencyoperations
x Vegetationmanagement
x Operatorpersonneltraining
x Protectionsystemsandtheircoordination
x Operatingtoolsandbackupfacilities
x Reactivepowerandvoltagecontrol
x Systemmodelinganddataexchange
x Communicationprotocolandfacilities
x Requirementstodetermineequipmentratings
x Synchronizeddatarecorders
x Clearercriteriaforoperationallycriticalfacilities
x Appropriateuseoftransmissionloadingrelief
Guideline (2) — Consistency within a Reliability Standard
1
NorthAmericanElectricReliabilityCorp.,119FERC¶61,145,orderonreh’gandcompliancefiling,120FERC¶61,145
(2007)(“VRFRehearingOrder”).
2
Id.atfootnote15.
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
2
ThecommissionexpectsarationalconnectionbetweenthesubͲrequirementViolationRiskFactor
assignmentsandthemainrequirementViolationRiskFactorassignment.
Guideline (3) — Consistency among Reliability Standards
ThecommissionexpectstheassignmentofViolationRiskFactorscorrespondingtorequirementsthat
addresssimilarreliabilitygoalsindifferentreliabilitystandardswouldbetreatedcomparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
WhereasinglerequirementcoͲminglesahigherriskreliabilityobjectiveandalesserriskreliability
objective,theVRFassignmentforsuchrequirementmustnotbewatereddowntoreflectthelowerrisk
levelassociatedwiththelessimportantobjectiveofthereliabilitystandard.
ThefollowingdiscussionaddresseshowtheSDTconsideredFERC’sVRFGuidelines2through5.The
teamdidnotaddressGuideline1directlybecauseofanapparentconflictbetweenGuidelines1and4.
WhereasGuideline1identifiesalistoftopicsthatencompassnearlyalltopicswithinNERC’sreliability
standardsandimpliesthattheserequirementsshouldbeassigneda“High”VRF,Guideline4directs
assignmentofVRFsbasedontheimpactofaspecificrequirementtothereliabilityofthesystem.The
SDTbelievesthatGuideline4isreflectiveoftheintentofVRFsinthefirstinstance;and,therefore,
concentrateditsapproachonthereliabilityimpactoftherequirements.
VRF for FAC-001-3:
TherearefourrequirementsinFACͲ001Ͳ3.Alloftherequirementswereassigneda“Lower”VRF.
VRF for FAC-001-3, Requirement R1:
TherewerenochangesmadetorequirementR1.ThecurrentFERCapprovedVRFsareproposedto
remainineffect.
VRF for FAC-001-3, Requirement R2:
TherewerenochangesmadetorequirementR2.ThecurrentFERCapprovedVRFsareproposedto
remainineffect.
VRF for FAC-001-3, Requirement R3:
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
3
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Alloftherequirementsin
FACͲ001Ͳ3areassigneda“Lower”VRF.ThisisalsoconsistentwiththecurrentFERCapproved
VRFinFACͲ001Ͳ2RequirementR3.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableFACͲ001Ͳ2standardRequirementR3whichhasan
approvedLowerVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
VRF for FAC-001-3, Requirement R4:
•
FERCGuideline2—Consistencywithinareliabilitystandardexists.Alloftherequirementsin
FACͲ001Ͳ3areassigneda“Lower”VRF.ThisisalsoconsistentwiththecurrentFERCapproved
VRFinFACͲ001Ͳ2RequirementR4.
•
FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableFACͲ001Ͳ2standardRequirementR4whichhasan
approvedLowerVRF.
•
FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•
FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
4
Justification for Assignment of Violation Severity Levels:
IndevelopingtheVSLsforthestandardsunderthisproject,theSDTanticipatedtheevidencethatwould
bereviewedduringanaudit,anddevelopeditsVSLsbasedonthenoncomplianceanauditormayfind
duringatypicalaudit.TheSDTbaseditsassignmentofVSLsonthefollowingNERCcriteria:
Lower
Moderate
Missingaminor
Missingatleastone
element(orasmall
significantelement(or
percentage)ofthe
amoderate
requiredperformance. percentage)ofthe
requiredperformance.
Theperformanceor
productmeasuredhas Theperformanceor
significantvalue,asit productmeasuredstill
almostmeetsthefull hassignificantvaluein
intentofthe
meetingtheintentof
requirement.
therequirement.
High
Severe
Missingmorethanone
significantelement(or
ismissingahigh
percentage)ofthe
requiredperformance,
orismissingasingle
vitalcomponent.
Theperformanceor
producthaslimited
valueinmeetingthe
intentofthe
requirement.
Missingmostorallof
thesignificant
elements(ora
significantpercentage)
oftherequired
performance.
Theperformance
measureddoesnot
meettheintentofthe
requirement,orthe
productdelivered
cannotbeusedin
meetingtheintentof
therequirement.
FERC’sVSLGuidelinesarepresentedbelow,followedbyananalysisofwhethertheVSLsproposedfor
eachrequirementinFACͲ001Ͳ3meettheFERCGuidelinesforassessingVSLs:
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
5
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
ComparetheVSLstoanypriorlevelsofnoncomplianceandavoidsignificantchangesthatmay
encouragealowerlevelofcompliancethanwasrequiredwhenlevelsofnoncompliancewereused.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Aviolationofa“binary”typerequirementmustbea“Severe”VSL.
Donotuseambiguoustermssuchas“minor”and“significant”todescribenoncompliantperformance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLsshouldnotexpandonwhatisrequiredintherequirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
...unlessotherwisestatedintherequirement,eachinstanceofnoncompliancewitharequirementisa
separateviolation.Section4oftheSanctionGuidelinesstatesthatassessingpenaltiesonaperͲ
violationͲperͲdaybasisisthe“default”forpenaltycalculations.
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
6
FACͲ001Ͳ3
VRFandVSLAssignments–November,
2015
VSLs for FAC-001-3 Requirement R2:
TherewerenochangesmadetorequirementR2.ThecurrentFERCapprovedVRFsareproposedtoremainineffect.
VSLs for FAC-001-3 Requirement R1:
TherewerenochangesmadetorequirementR1.ThecurrentFERCapprovedVSLsareproposedtoremainineffect.
7
TheNERCVSL
Guidelinesare
satisfiedby
incorporating
levelsof
noncompliance
performance.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.
TheproposedVSLsare
similartothecurrentFERC
approvedVSLsinFACͲ001Ͳ2
RequirementR3.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLsarenot
binary.ProposedVSL
languagedoesnotinclude
ambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyonthenumberof
partstheentityfailedto
address.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
R3.
R#
Compliance with
NERC VSL
Guidelines
VSLs for FAC-001-3 Requirement R3:
8
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
TheNERCVSL
Guidelinesare
satisfiedby
incorporating
levelsof
noncompliance
performance.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.
TheproposedVSLsare
similartothecurrentFERC
approvedVSLsinFACͲ001Ͳ2
RequirementR3.
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
ProposedVSLisbinaryand
thereforeonlyhasasevere
VSL.ProposedVSLlanguage
doesnotincludeambiguous
termsandensures
uniformityandconsistency
inthedeterminationof
penaltiesbasedonlyonthe
numberofpartstheentity
failedtoaddress.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2
Guideline 1
FACͲ001Ͳ3
VRFandVSLAssignments–November,2015
R4.
R#
Compliance with
NERC VSL
Guidelines
VSLs for FAC-001-3 Requirement R4:
9
ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.Proposed
VSLsareconsistentwith
therequirement.
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 3
ProposedVSLsare
basedonsingle
violationsandnota
cumulative
violation
methodology.
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
Guideline 4
CalculatingandUsingReportingACEinaTieLineBiasControlProgram
Introduction:
TieLineBias1(TLB)controlhasbeenusedasthepreferredcontrolmethodinNorthAmericafor75years.Inthe
early1950’sthetermAreaControlError(ACE)wasdevelopedforthespecificimplementationofcoordinatedTie
LineBiascontrolnowinusethroughouttheworld.Thisdocumentprovidesresponsibleentitiesguidelinesfor
usingbothrequiredspecificsandthebestpracticesforcalculatingandusingReportingACE2incoordinationwith
othermeasurestoprovidereliablefrequencycontrol.Whiletheincorporationofthesebestpracticesisstrictly
voluntary;reviewing,revising,ordevelopingaprocessusingthesepracticesishighlyencouragedtopromote
andachievereliabilityfortheBulkElectricSystem.
ThefollowingdefinitionsareincludedintheNERCGlossary:
Definition:
5/11/2015
ActualFrequency
FA
TheInterconnectionfrequencymeasuredinHertz(Hz).
Definition:
5/11/2015
ActualNetInterchange
NIA
ThealgebraicsumofactualmegawatttransfersacrossallTieLines,includingPseudoͲTies,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection.ActualmegawatttransfersonasynchronousDC
tielinesdirectlyconnectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
1
2
CapitalizedtermsholdthesamedefinitionasintheNERCglossarythroughoutthisdocument.
TheCPS1measurewasamongthefirstoftheresultsbasedmeasuresdevelopedbyNERC.Itdefinednothowtoperform
control,butinsteaddefinedthetargetcontrolresultsthatweretobeachieved,andamethodtomeasurewhetherornot
thatdefinedcontroltargethadbeenmet.Asaresult,whenCPS1wasimplemented,theACEEquationusedinthat
measurewasalsospecifiedwithinthatstandard.
Historically,AreaControlError(ACE)hasbeenusedtodescribemanytermsinvolvedinTLBControl.WithinaBAA’s
AutomaticGenerationControl(AGC)algorithmtheremaybemorethanoneACEvalueinuse.Insomesystems,theACE
isfilteredpriortodeterminingcontrolactionsinordertosmooththecontrolsignals;or,theremaybeadditional“feedͲ
forward”termsaddedtoACEinanticipationoffuturechanges(e.g.anticipatedramps,changesinambientlightat
sunriseorsunset).TheremaybegaintermsthatmodifycertainvariablessuchastheFrequencyBiasSettingtoimprove
thequalityofcontrolforthespecificcharacteristicsofthatparticularBAA.
SomeauditorshaveraisedcomplianceissuerelatedtotheuseofsuchmodificationstotheACEusedwithintheLoadͲ
FrequencyControl(LFC)system(alsoreferredtoasAGC)andrequiredchangesintheAGCsystemtoconformtothe
definitionofACEinBALͲ001.Theterm“ReportingACE”wasdevelopedandisusedinplaceofthetermACEtoprovidea
consistentperformancemeasurementusingReportingACEandtoremoveanyunnecessaryrestrictionsonthe
specificationofACEwithintheLFCsystem.
1
2
Definition:
AutomaticTimeErrorCorrection
IATEC 5/11/2015
TheadditionofacomponenttotheACEequationfortheWesternInterconnectionthatmodifiesthecontrol
pointforthepurposeofcontinuouslypayingbackprimaryInadvertentInterchange(PII)tocorrect
accumulatedtimeerror.AutomaticTimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Τࢌࢌࢋࢇ
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ࡵ܂ۯ۳۱
ሺି܇ሻכ۶
whenoperatinginAutomaticTimeErrorCorrectionmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
x
x
x
x
x
x
x
x
x
x
x
x
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAAbetween0.2*|Bi|andL10,0.2*|Bi|LmaxL10.
L10ൌ ͳǤͷ ߝ כଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare(RMS)
valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragivenyear.The
bound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
Y=Bi/BS.
H=NumberofhoursusedtopaybackprimaryInadvertentInterchangeenergy.ThevalueofHissetto3.
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactual–Bi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor,
where:
ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontimemonitorcontrol
centerclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲPeak
accumulationaccountingisrequired,
where:
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
Definition:
FrequencyBiasSetting
B
4/1/2015
Anumber,eitherfixedorvariable,usuallyexpressedinMW/0.1Hz,includedinaBalancingAuthority’sArea
ControlErrorequationtoaccountfortheBalancingAuthorityArea’sinverseFrequencyResponsecontribution
totheInterconnection,anddiscourageresponsewithdrawalthroughsecondarycontrolsystems.
3
Definition:
5/11/2015
InterchangeMeterError
IME
Aterm,normallyzero,usedintheReportingACEcalculationtocompensatefordataorequipmenterrors
affectinganyothercomponentsoftheReportingACEcalculation.
Definition:
ReportingACE
RACE 5/11/2015
ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError(ACE)measuredinMWincludes
thedifferencebetweentheBalancingAuthorityArea’sActualNetInterchangeanditsScheduledNet
Interchange,plusitsFrequencyBiasSettingobligation,pluscorrectionforanyknownmetererror.Inthe
WesternInterconnection,ReportingACEincludesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
=
ActualNetInterchange.
x NIA
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
=
AutomaticTimeErrorCorrection.
x IATEC
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciplesofTieͲlineBias
(TLB)ControlandrequiretheuseofanACEequationsimilartotheReportingACEdefinedabove.Any
modification(s)tothisspecifiedReportingACEequationthatis(are)implementedforallBAAsonan
Interconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBiascontrolwillprovidea
validalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’
generation,load,andlossisthesameastotalInterconnectiongeneration,load,andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimesandthesumof
allBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEtermcorrectsforknown
meteringorcomputationalerrors.)
4
Definition:
3/16/2007
ScheduledFrequency
FS
60.0Hz,exceptduringamanualTimeErrorCorrection.
Definition:
5/11/2015
ScheduledNetInterchange
NIS
Thealgebraicsumofallscheduledmegawatttransfers,includingDynamicSchedules,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection,includingtheeffectofscheduledramps.
ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromScheduledNetInterchange.
Structure:
TheeffectiveuseofReportingACEwithinaTLBcontrolprogramshouldaddressthefollowingcomponents:
(I)
(II)
(III)
(IV)
(V)
(VI)
(VII)
(VIII)
ManagementRolesandExpectations
InformationTechnologyRoles
SystemOperatorRoles
ManualSourceDataEntry
AutomaticallyCollectedSourceData
UsesofReportingACE
HistoricDataManagement
SpecialConditionsandCalculations
Eachindividualcomponentshouldaddressprocessesandprocedures,evaluationofanyissuesorproblems
alongwithsolutions,testing,training,andcommunications.Theseprovisionsandactivitiestogetherwillbe
referredtoastheTieLineBiascontrolprogram.
EachresponsibleentityshouldevaluateallofitsusesforReportingACEinitsoperationsanditsreliability
measurement.ReportingACEisoneofthemostimportantsinglemeasurementsavailabletoindicatethe
currentstateoftheResponsibleEntity’scontributiontointerconnectionreliability.3ReportingACEisalsoused
asanintegralpartofthemeasurementsusedinBALͲ001andBALͲ002.Technicalrequirementsassociatedwith
theparametersusedinthecalculationofReportingACEarespecifiedinBALͲ003andBALͲ005.
I.
ManagementRolesandExpectations
ManagementplaysanimportantroleinmaintaininganeffectiveTLBcontrolprogram.The
managementroleandexpectationsbelowprovideahighͲleveloverviewofthecoremanagement
responsibilitiesrelatedtoeachTieLineBiascontrolprogram.Themanagementofeachresponsible
entityshouldtailortheserolesandexpectationstofitwithinitsownstructure.
a. Setexpectationsforsafety,reliability,andoperationalperformance.
3
WhenconfiguredwithaFrequencyBiasSettingequaltotheactualFrequencyResponseoftheBAA,ReportingACEwill
reflecttheBAA’sobligationtomatchitsactualinterchange,lesstheimpactfromitscurrentFrequencyResponseoffset,
toitsscheduledinterchange.
5
b.
c.
d.
e.
II.
AssurethataTLBcontrolprogramexistsforeachresponsibleentityandiscurrent.
ProvideannualtrainingontheTLBcontrolprogramanditspurposeandrequirements.
EnsuretheproperexpectationofTLBcontrolprogramperformance.
Shareinsightsacrossindustryassociations.
InformationTechnology(IT)Roles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEandsourceinformationarealwayscurrentandcorrect.
c. ImplementtheTLBcontrolprograminRealͲtime.
d. EnsurethattheEMSsupportsthemanualdataentryofallsourcedatarequiredtobeenteredbyIT
staff,systemoperationsstaff,andSystemOperatorsandproperlymanagesthatdataonceentered.
e. EnsurethattheEMSsupportsandmanagestheautomaticcollectionofallsourcedatathatis
requiredtobemeasuredinrealͲtimethroughtelemetryanddataexchangeincludingdataquality
informationtoindicatedatavalidity.
f. EnsurethattheprogramsthatmanagedatausedtocalculatecomponentsofReportingACE,
ReportingACEitself,andsubsequentmeasuresbasedonReportingACEareuptodateandcorrect
asidentifiedby,butnotlimitedtothefollowingcalculationsandequations:
1) ActualNetInterchange4(NIA):
AllBAAsinvolvedaccountforthepowerexchangeandassociatedtransmissionlossesasactual
interchangebetweentheBAAs,bothintheirACEandReportingACEequationsandthroughout
alloftheirenergyaccountingprocesses.
i. Calculateforeachscan.5
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
4
Bydefinition“ActualmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromActualNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielinesconnectedto
anotherinterconnectionisprovidedin“SpecialConditionsandCalculations”sectionofthisdocument.
5
ActualNetInterchangescanͲratevaluesarealsousedasoneoftheprimaryinputstothecalculationofFrequency
ResponseMeasure(FRM)onFRSForm1andFRSForm2.
6
2) ScheduledNetInterchange6(NIS):
i. Calculateforeachscan.
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
(Thisvaluediffersfromtheblockaccountingvalue.)
Note: DynamicSchedulesaretobeaccountedforasInterchangeSchedulesbythesource,
sink,andcontractintermediaryBAA(s),bothintheirrespectiveACEandReportingACE
equations,andthroughoutalloftheirenergyaccountingprocesses.
3) FrequencyError('F=(FA–FS)):
i. Calculateforeachscan.
ii. CalculateclockͲminuteaveragefromvalidsamplesavailablewithineachclockͲminute7
whereatleasthalfofthescanͲratesamplesarevalid.
4) FrequencyTriggerLimit–Low(FTLLow)8:
CalculatetheFrequencyTriggerLimit–LowforeachclockͲminutewhereatleasthalfofthescan
ratesamplesarevalidbysubtractingthreetimesEpsilon1fromtheScheduledFrequency(FS).
5) FrequencyTriggerLimit–High(FTLHigh)9:
CalculatetheFrequencyTriggerLimit–HighforeachclockͲminutewhereatleasthalfofthe
scanratesamplesarevalidbyaddingthreetimesEpsilon1totheScheduledFrequency(FS).
6) AccumulatedprimaryInadvertentInterchange(PII):CalculatedeachhourforWECCBAAsonly.
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
7) AutomaticTimeErrorCorrection(IATEC):CalculateforeachhourforWECCBAAsonlyfor
inclusionintheACEandReportingACEEquationforthenexthour.
Τࢌࢌࢋࢇ
ࡵ܂ۯ۳۱
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ሺିࢅሻࡴכ
whenoperatinginATECmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
6
Bydefinition“ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherinterconnection
areexcludedfromScheduledNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielines
connectedtoanotherinterconnectionisprovidedinthe“SpecialConditionsandCalculations”sectionofthisdocument.
7
ClockͲminuteaveragesareusedforthecalculationofACEandFrequencyErrorinCPS1andBAALtoeliminatethe
transientvariationsoftieͲlineflowsandfrequencyerrorusedinthecalculationofperformancemeasures.TheoneͲ
minuteperiodwaschosenbecauseitisevenlydivisiblebyallwholeͲsecondscanrateslessthanthemaximumspecified
scanrateofsixseconds.ThisassuresgreatercomparabilityofperformancedataamongBAswithdifferentscanrates.
8
Thisvariablecouldbeenteredmanuallyaslongasitischangedeverytimeamanualtimeerrorcorrectionisstartedor
stopped.Ifmanualtimeerrorcorrectioniseliminated,itcouldbecomeaconstantandenteredmanually.
7
8) ReportingACE:
i. Calculateforeachscan.
ii. CalculatedaverageforeachclockͲminuteforBAAsusingafixedFrequencyBiasSetting
whenatleasthalfofthevaluesarevalid.9
9) ComplianceFactor10:
i. CalculateforeachscanwherebothReportingACEandFrequencyErrorarevalid.
ii. CalculateforeachclockͲminutewhereboththeaverageclockͲminuteFrequencyErrorand
theaverageclockͲminuteReportingACEarevalid.11
10) ClockͲhourcompliancefactor8:
CalculateforeachhourbysummingthevalidclockͲminutecompliancefactorsforthehourand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthehour.
11) Monthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthemonthanddividingby
thenumberofvalidclockͲminutecompliancefactorsinthemonth.
12) 12Ͳmonthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthe12Ͳmonthperiodand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthe12Ͳmonthperiod.
13) CPS1compliancefactor:
CalculatetheCPS1compliancefactorbydividingthe12Ͳmonthcompliancefactorbythesquare
oftheEpsilon1valuefortheInterconnection.
14) CPS1:
i. CalculatetheCPS1scanrateperformancebydividingthescanratecompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachscanwitha
validcompliancefactor.
ii. CalculatetheCPS1clockͲminuteperformancebydividingtheclockͲminutecompliance
factorbythesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthat
valuefrom2andmultiplyingtheresultby100toconverttoapercentageperformancefor
eachclockͲminutewithavalidcompliancefactor.
iii. CalculatetheCPS1clockͲhourperformancebydividingtheclockͲhourcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
9
TheaverageofthevalueoftheratioofthescanratevalueofReportingACEdividedbythescanratevalueofͲ10times
theFrequencyBiasSettingforthoseBAsusingavariableFrequencyBiasSetting,whereatleasthalfoftheratiovalues
arevalid.
10
UsedforCPS1.
11
ThecompliancefactoriscalculatedwhentheaverageofthevalueoftheratioofthescanratevalueofReportingACE
dividedbythescanratevalueofͲ10timestheFrequencyBiasSettingforthoseBAsusingavariableFrequencyBias
Setting,whereatleasthalfoftheratiovaluesarevalidandtheaverageclockͲminuteFrequencyErrorisvalid.
8
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
iv. CalculatetheCPS1monthlyperformancebydividingthemonthcompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲminute
withavalidcompliancefactor.
v. CalculatetheCPS112Ͳmonthperformancebydividingthe12Ͳmonthcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
15) BalancingAuthorityACELimitͲLow(BAALLow):
i. CalculatethescanrateBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
16) BalancingAuthorityACELimitͲHigh(BAALHigh):
i. CalculatethescanrateBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
17) BalancingAuthorityACELimitͲLowCompliance:
i. AlarmBAALLowpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisbelowtheclockͲminuteBAALLow.
ii. IndicateBAALLownonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
belowtheclockͲminuteBAALLowformorethan30ͲconsecutiveclockͲminutes.
18) BalancingAuthorityACELimitͲHighCompliance:
i. AlarmBAALHighpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisabovetheclockͲminuteBAALHigh.
ii. IndicateBAALHighnonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
abovetheclockͲminuteBAALHighformorethan30consecutiveclockminutes.
g. EnsurethattheEMSsupportstheretentionofallhistoricdataincludingdataqualityinformation
requiredtoberetainedtosupportcontinuingoperationsandauditrequirements.
9
h. EnsurethattheEMSsupportsandmanagesthepresentationofallinformationrequiredtobe
availabletotheSystemOperatorforrealͲtimeoperations,operationsstaffforevaluationof
operations,andauditorsforcomplianceconfirmation.
i.
ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
III.
SystemOperatorandOperationsStaffRoles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEinformationisalwayscurrentandcorrect.
c. ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
d. ImplementtheTLBcontrolprograminRealͲtime.
IV.
ManualSourceDataEntry
ReportingACEiscalculatedinRealͲtime,atleasteverysixseconds12,bytheResponsibleEntity’sEnergy
ManagementSystem(EMS),andmaybepartiallybasedonsourcedatamanuallyenteredintothat
system.Thefollowingsourcedatamaybeentered:
NIA(ActualNetInterchange):Thetelemetryvaluesofactualtieflows,includingpseudoͲties,between
AdjacentBalancingAuthorityAreasmaynotbeavailablefromanautomaticcollectionsource,
requiringmanualentryofestimatedflows.Thesemanualentriesshouldbeperformedina
mannerthatreasonablyassuresequalmagnitudeandoppositesignvaluesareusedbythe
AdjacentBalancingAuthorityAreasenteringthemanualdata.Iftheactualflowestimatesare
thesamefortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedto
thetwoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failureto
matchactualflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
NIS(ScheduledNetInterchange):Thepowertransferschedules,includingtheschedulerampswhere
applicable,areprocessedbytheEMS.Ifscheduledflowestimatesareequalandhaveopposite
signsfortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedtothe
twoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failuretomatch
scheduledflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
B(FrequencyBiasSetting):TheFrequencyBiasSetting,orminimumrequiredvalue,fortheBalancing
AuthorityAreaisspecifiedbycalculationsperformedaspartofcompliancewithBALͲ003Ͳ1Ͳ
FrequencyResponseandFrequencyBiasSetting;
R2.
EachBalancingAuthorityAreathatisamemberofamultipleBalancingAuthority
AreaInterconnectionandisnotreceivingOverlapRegulationServiceandusesafixed
FrequencyBiasSettingshallimplementtheFrequencyBiasSettingdeterminedin
accordancewithAttachmentA,asvalidatedbytheERO,intoitsAreaControlError
12
BALͲ005Ͳ1BalancingAuthorityControlͲR2.TheBalancingAuthorityshallusenogreaterthanasixͲsecondscanratein
acquiringdatanecessarytocalculateReportingACE.
10
(ACE)calculationduringtheimplementationperiodspecifiedbytheEROandshall
usethisFrequencyBiasSettinguntildirectedtochangebytheERO.13
10isthefactor(100.1Hz/Hz)thatconvertstheFrequencyBiasSettingunitstoMW/Hz.
FS(ScheduledFrequency):ScheduledFrequency,normally60Hz,ismanuallyadjustedonacoordinated
basiswhendirectedtodosobytheInterconnectionTimeMonitorasspecifiedinBALͲ004Ͳ0.14It
isimportantforallBAAsonaninterconnectiontomaketheseadjustmentsonacoordinated
basissothatallBAAsarecontrollingtothesameScheduledFrequencyatalltimes.
IME(InterchangeMeterError):Thisterm,normallyzero,isavailableforusebytheSystemOperatoror
operationsstafftoaddacorrectiontermintheReportingACEcalculationtocompensatefor
dataorequipmenterrorsaffectinganyothercomponentsidentifiedbyanalysisofhistoricdata
demonstratingtheexistenceoferrors,usuallyerrorsbetweenintegratedhourlyscanͲratedata
andhourlyagreedtoaccumulatedmeterdata.(SeetheSpecialConditionsandCalculations
sectionofthisdocumentforadditionalinformation)
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|B|andL10,0.2*|B|чLmaxчL10.
YisnormallycalculatedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.
Hisnormallysetto3andusedbytheATECprogramintheEMSforBAsontheWestern
Interconnection.Itrepresentsthenumberofhoursoverwhichtheprimaryinadvertent
interchangeispaidback.
BSisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Itrepresentsthe
sumoftheminimumFrequencyBiasSettingsforallBAAsontheInterconnection.
ȴTEisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Insomecases,it
maybecalculatedbytheEMSbasedonthefactorsintheȴTEequation.ȴTEisthehourly
changeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor.
TDadjisanadjustmentforthedifferencesbetweenthelocalclockinthelocaltimestandardandthe
InterconnectiontimemonitorcontrolcenterclockssothatthelocalEMScancalculatethe
correctȴTEfortheBAAsandusedbytheATECprogramintheEMSforBAAsontheWestern
Interconnection.
TEoffsetisenteredasinstructedbytheInterconnectiontimemonitor.
H1istheRMSLimitforthe1Ͳminuteaveragefrequencyerrorfortheinterconnection.
13
Asanoteofinterest,thenewproceduresputforthwithBALͲ003Ͳ1willresultinthereductionofminimumFrequency
BiasSettingvaluesonthemultipleBAinterconnectionstobringthemclosertothenaturalmeasuredFrequency
Responseoftheinterconnection.TherulerequiringaminimumFrequencyBiasSettingof1%ofpeakloadintheNERC
Standardsdatesbackto1962whenNAPSIC,theprecursortotheNERCOperatingCommittee,codifiedthe
recommendationsoftheInterconnectedSystemsGroupmadein1956tosetaminimumof50%ofthenaturalmeasured
responsewhichwas2%ofpeakloadatthattime.The1%figureisnowmorethan200%ofthenaturalmeasured
responsefortheEasternInterconnectionandinsomecasesisapproachingavaluethatcouldresultininstabilitybybeing
toohigh.Thelogicjustifyingaminimumofthenaturalresponseisstillvalid.
14
Thisisconsistentwithcondition3intheReportingACEDefinition:“TheuseofacommonScheduledFrequencyFSforall
areasatalltimes.”
11
V.
AutomaticallyCollectedSourceData
ReportingACEiscalculatedinRealͲtime,atleastasfrequentlyaseverysixseconds15,bytheresponsible
entity’sEnergyManagementSystem(EMS)predominantlybasedonsourcedataautomaticallycollected
bythatsystem.Also,thedatamustbeupdatedatleasteverysixsecondsforcontinuousscantelemetry
andupdatedasneededforreportͲbyͲexceptiontelemetry.
Inaddition,dataqualityinformation(usuallyintheformofdataqualityflagsassociatedwitheachdata
value)mustberetainedandpresentedinrealͲtimetotheSystemOperators.Thisdataquality
informationispresentedtotheSystemOperatortohavesituationalawarenesswithrespecttothe
qualityofthedatainputsandfinalcalculatedresult.Itislaterusedtodeterminewhichdataisvalidfor
useinperformancecalculationssuchasCPS1,BAAL,DCS,andfrequencyresponseobligation(FRM).
NIA(ActualNetInterchange):ThetieͲlinevaluerepresentingeachtieͲlineflowandpseudoͲtiequantity
iscollectedattherequiredscanrateofsixsecondsorless.16,17,18,19Datathatisofquestionableaccuracy
ortimelinessisflaggedwithanappropriatedataqualityflag.Thisinformationispresentedtothe
SystemOperatortosupportsituationalawareness.20TheEMSsumstheindividualflowvaluesonalltie
linesandpseudotieswithalladjacentBAAsatthescanrateandincludesthisvalueasNIAinthe
ReportingACEequationcalculation.TheresultisaseriesofNIAvaluesattheEMSscanrateand
associateddataqualityflags.Theassociateddataqualityofthetelemetryelementispassedtothe
resultofallcalculationsusingthatelement.
NIS(ScheduledNetInterchange):MostinterchangeschedulesandsomeDynamicSchedulesare
enteredintotheEMSinasummaryformateitherasindividualschedules,schedulenetswitheach
AdjacentBalancingAuthorityArea,orafinalScheduledNetInterchange.Theseschedulesareconverted
intoscanͲrateschedulesbytheEMS.TheEMScalculatestheScheduledNetInterchange,where
applicable,bysummingallindividualschedulevaluesornetswitheachAdjacentBalancingAuthority
AreaforallregularandDynamicSchedulesandincludestheresultasNISintheACEequation.
FA(ActualFrequency):Actualfrequencyisprovidedbyafrequencymeasuringdeviceattheaccuracy
specifiedinBALͲ00521attheEMSscanrate.Ifafrequencyvalueisnotavailable,thevalueforthatscan
ismarkedinvalid.
15
BALͲ005Ͳ1BalancingAuthorityControl–“R2.TheBalancingAuthorityAreashallusenogreaterthanasixͲsecondscan
rateinacquiringdatanecessarytocalculateReportingACE.”
16
DatatransmittedatarateslowerthanthescanrateoftheremotesensingequipmentmayrequiretheinclusionofantiͲ
aliasingfilteringatthesourceofthemeasurementtoeliminatetheriskofaliasinginthedatatransmittedtotheEMS.
Seetheattacheddocumenttitled“AntiͲaliasingFiltering.”
17
ItisacceptabletocollecttieͲlineflowdatafromRTUsthatusereportbyexceptionaslongasthoseRTUscansupportthe
scanrateofsixsecondsorlesswhendataischangingrapidlyandbothadjacentBAAsarereceivingcomparabledatato
keepthemeasuredflowsequivalent.
18
ThesixͲsecondscanratenotonlyassuresthatdatacollectedisclosetoRealͲtime,italsolimitsthelatency(timeskew)
associatedwiththedatacollection.
19
Theaccuracyoftheflowdataissetbythoseusingtheflowdatafortransmissionflowmanagement.AswithallACEdata,
aslongasbothadjoiningBAAsareusingthesamevaluesfortieͲlineflow,theeffectsofanyerrorinflowmeasurement
willbeconfinedtothetwoadjacentBAAs.
20
Indicationsofsuspectdataareusuallyindicatedwithcolorchangesand/oralarms.
21
BALͲ005–AutomaticGenerationControlspecifiesanaccuracyofч0.001Hz(equivalenttoч+/Ͳ0.0005Hz)fortheDigital
FrequencyTransducer.
12
IIactual(InadvertentInterchange):ThistermisonlyusedintheWesternInterconnectionACEcalculation.
InadvertentInterchange“Actual”fortheprevioushouriscalculatedbytheEMSfromtheprevious
hour’sdataasthedifferencebetweentheintegratedhourlyaverageScheduledNetInterchangeandthe
integratedhourlyaverageActualNetInterchange.(Blockschedulesarenotusedforthiscalculation.)
t(ManualTimeErrorcorrectionminutesinthehour):ThenumberofminutesofmanualTimeError
correctioninthehour.
VI.
UsesofReportingACE
a. ReportingACEiscurrentlyusedtomeasuresecondaryfrequencycontrolwithinTLBcontrolonallof
theInterconnections.22Consequently,ReportingACEisoneoftheprimarymeasurement
parametersinmanyoftheNERCBalancingStandards.Thefollowingstandardsrequiretheuseof
ReportingACEaspartoftheperformancemetricsorsetrequirementsassociatedwiththe
calculationofReportingACE.
i. BALͲ001Ͳ1–RealPowerBalancingControlPerformanceandBALͲ001Ͳ2–RealPowerBalancing
ControlPerformance.
ii. BALͲ002Ͳ1–DisturbanceControlPerformanceandBALͲ002Ͳ2–DisturbanceControlStandard–
ContingencyReservefromaBalancingContingencyEvent(whenapproved).
iii. BALͲ005Ͳ0.2b–AutomaticGenerationControlandBALͲ005Ͳ1–BalancingAuthorityControl
(whenapproved).
iv. BALͲ006Ͳ2InadvertentInterchange.
b. TheindustrymayalsoconsidertheuseofReportingACEinthefuturetoevaluatetherules
associatedwithtransmissionloading.
VII.
VIII.
IX.
HistoricDataManagement
TheindustrycurrentlyrequirestheretentionofdatasupportingthecalculationofReportingACEand
compliancemeasurementsbasedinpartonReportingACEtosupporttheNERCcomplianceaudit
process.ThisdataretentionmustbeconsideredasanintegralpartoftheReportingACEand“TLB
controlprogram”.
SpecialConditionsandCalculations
IME(InterchangeMeterError):BALͲ005Ͳ1R6requires,“EachBalancingAuthorityAreathatiswithina
multipleBalancingAuthorityAreainterconnectionshallimplementanOperatingProcesstoidentifyand
mitigateerrorsaffectingthescanͲrateaccuracyofdatausedinthecalculationofReportingACE.”
Ideally,errorsidentifiedshouldbecorrectedimmediately,butthisisnotalwayspossible.TheIMEterm,
normallyzero,canbeusedbytheSystemOperatororoperationsstafftoaddacorrectionterminthe
ReportingACEcalculationcorrectingerrorsaffectingthescanͲrateaccuracyofdata,thusmitigatingthe
errorinthecalculationofReportingACEuntiltelemetryerrorscanbecorrected.
22
OnsingleBAAInterconnections,theACEEquationreducestoasingleterm,Ͳ10B(FA–FS),becausetherearenotielines
orschedulestoincludeinthefirstterm,(NIA–NIS),andthereisnoIMEtermtocorrectfortielineordynamicschedule
measurementerrorsinthefirstterm.
13
ThecalculationoftheIMEistheoneoftheresultsofthisrequiredOperatingProcess.It
compensatesfordataorequipmenterrorsaffectingcomponentsofReportingACEidentifiedby
analysisofhistoricdata.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataand
hourlyaccumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulatedmeter
dataoftwoadjacentBAAs.TheprocessusedforincludingadjustmentsintheIMEtermshouldbe
basedongoodqualitycontrolmethods.23
ThegoalassociatedwiththeuseoftheIMEistoencouragethescanͲratevaluesofactualand
scheduledinterchangebetweenAdjacentBalancingAuthoritiestobeequalinmagnitudeandhave
oppositesigns.24Unfortunately,thesevaluescannotbedirectlycomparedwitheachotherbecause
ofdifferencesbetweenscantimeanddifferencesbetweenscanͲratesbetweenBAAs.Wheninitially
configured,allBAsused“DigitaltoAnalog”convertersand“AnalogtoDigital”converterstotransmit
tieͲlineflowsandaccumulatedMWhvaluesfromthecommonmeteringpointrequiredinthe
standardstotheBA’sEMS.These“DtoA”and“AtoD”convertersaresubjecttoerrorandrequire
frequentcalibration,andalthough,manyhavebeenreplacedbydigitaltelemetry,theystillexistand
requireoversight.AnydifferencebetweenthescanͲratevaluesagreedtobyAdjacentBAAsthatis
notincludedintheerrormitigationprocesswillbepassedtotheinterconnectionformanagement
andwillnotbeincludedintheperformancemeasuressuchasCPS1,BAALandFRM.
EnergyManagementSystemsarecapableofintegratingthescanͲratevaluesusedforthecalculation
ofReportingACEandprovidingthoseintegratedvaluesforcomparisontotheaccumulated
megawattͲhourvaluesforthesamemeters.Iftheintegratedscanratevaluesareclosetothe
accumulatedmegawattͲhourvalues,thenonecanconcludethatthescanͲratevaluesaccurately
representtheaccumulatedvalues.Thefinalstepinthisprocessincludesacomparisonand
agreementontheaccumulatedmegawattͲhourvaluesbetweentheAdjacentBAAssharingthe
measurement.IfthedifferencesbetweenaccumulatedvaluesbetweenAdjacentBAAsisnot
includedinthisprocess,anyadjustmentstotheaccumulatedvaluesmadebyaBAAtoachieve
agreementwithanadjacentBAAwillbeexcludedfromtheanalysisandwillnotbemitigated.This
informationusedinconjunctionwithasimilaranalysisofthescanratevaluesforthesame
measurementbytheAdjacentBalancingAuthorityAreaincludinganalysisofanydifferences
betweentheaccumulatedvaluesandtheagreedtoaccumulatedvalues.Thistotalprocessprovides
reasonableassurancethatthescanͲratetielineflowsorthedynamicschedulesusedbyAdjacent
BAAsareconsistentwithoneanotherconfiningcontrolproblemswithintheboundariesofthe
AdjacentBAAs.
23
AdjustmentstotheIMEtermshouldfollowgoodqualitycontrolmethodsandexcludetamperingasdemonstratedbythe
Deming’sFunnelExperiment,http://blog.newsystemsthinking.com/wͲedwardsͲdemingͲandͲtheͲfunnelͲexperiment/.
24
AslongasthescanͲratetielineflowsandscheduledflowsmatchforAdjacentBalancingAuthorityAreas,anyproblems
withthemeasurementofbalancingontheinterconnectionwillbeconfinedtowithintheboundariesofthoseAdjacent
BalancingAuthorityAreas.Anymismatchwillpassthedifferencetotheinterconnectionandwillresultinfrequency
controlerrorthatwilltobeexcludedfromperformancemeasurementandmanagedbyallBAAsthroughthefrequency
biastermsoftheirReportingACE.
14
TheseerrorcorrectionadjustmentscanbeusedtocorrecterrorsintheNIAorNIS25termsfor
ReportingACEandothermeasurementsthatdependuponanaccurateActualNetInterchange
and/oranaccurateScheduledNetInterchange.Thesamelogicandevaluationprocessesthatare
validforinclusionintheIMEtermoftheReportingACEequationshouldalsobevalidasadjustments
tothescanratetieͲlineflowsusedforthemeasurementofFrequencyResponseaspartoftheBALͲ
003Ͳ1.
a. UseofSourceͲSinkPairsforAsynchronousDCTieLinestoAnotherInterconnection:Oneofthe
primaryrulesforinsuringthevalidityoftheReportingACEequationis,“Allportionsofthe
InterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’generation,load,and
lossisthesameastotalInterconnectiongeneration,load,andloss.”Thisisaccomplishedby
requiringtheinclusioninReportingACEofalltielines,pseudoties,interchangeschedulesand
DynamicSchedulestoAdjacentBalancingAuthorityAreasandonlyAdjacentBalancingAuthority
AreasonthesameInterconnection,andrequiringtheexclusionofallasynchronousDCtielinesand
associatedscheduledinterchangewithBalancingAuthorityAreasonadifferentInterconnection
fromReportingACE.Followingthissimpleruleinsuresthatallloads,lossesandgenerationare
properlyincludedwitheachInterconnection.
InsteadofincludingthepowertransfersfromanasynchronousDCtielinebetweentwo
InterconnectionsasanormalinterchangetransferbetweentwoBAAs,thisformofpowertransfer
shouldbeincludedasthoughitisalinkedsourceͲsinkpairforthepurposesofmanagingfrequency
controlwithinatielinebiascontrolprogram.OneterminalofanasynchronousDCtielinewill
appeartothereceivingInterconnectionandreceivingBAAasanenergyresourcesimilartoa
generator.ThisisthesourceendofthesourceͲsinkpair.Theotherterminalofthesame
asynchronousDCtielinewillappeartothesupplyingInterconnectionandsupplyingBAAasan
energysinksimilartoaload.ThisisthesinkendofthesourceͲsinkpair.
InterchangetransactionslinkedtoeitherthesourceorsinkfromotherBAAsonthesame
Interconnectionasthesourceorsinkwillschedulethosetransactions,includethosetransactionsin
ReportingACE,andmanagethosetransactionsinasimilarmannertoanyotherenergytransaction.
OnlytheBAAactingasthesourceorthesinkfortheDCtielinewillexcludetheasynchronoustie
linefromitsReportingACEwhileincludingalltransactionswithAdjacentBAAsonthesame
InterconnectionassociatedwiththatsourceorsinkpowertransferintheirReportingACE.
25
ErrorsintheNISwouldonlyoccurandonlysupportcorrectionincaseswherethereisameasurementerrorassociated
withaDynamicSchedule.
Draft # 3 August 17, 2015
[Capitalized words will have the same meaning as listed in the NERC Glossary of
Terms and Rules of Procedures unless defined otherwise within this document.]
INADVERTENT INTERCHANGE
Relationship to Reliability, Industry Practices, and Options for the
Future
Introduction
The purpose of this document is to explain why a North American Electric Reliability
Corporation (NERC) Reliability Standard is not required for Inadvertent Interchange (also
referred to herein as Inadvertent) accounting and that Inadvertent accounting should be addressed
through commercial means.
Included within this document are the typical practices that Balancing Authority Areas (BAA)
within the NERC area currently follow, which allows for the development of commercial
methods to address inadvertent balances. These practices provide a method for isolating and
eliminating the source(s) of Inadvertent accounting errors.
Simple data errors (either value or sign) made in the acquisition of Actual Net Interchange or
Scheduled Net Interchanges may become operating problems if they become a part of the
Reporting ACE calculation. Regarding the deliberate creation or reduction of Inadvertent, this
happens through implementation of bilateral or unilateral Inadvertent payback or a false
Schedule offset to correct a perceived metering error. Also, Inadvertent is created or reduced
because it is calculated using hourly Actual Net Interchange and Scheduled Net Interchanges
without compensation for ramps. Finally, Inadvertent is inherently created because generation
cannot physically follow the electrical demands of the system with absolute precision. Viewed
from a total interconnected network (Interconnection) perspective, when the summation of all
Balancing Authority Area Inadvertent within an Interconnection no longer sums to zero, there
will exist a generation surplus or deficiency on the Interconnection. Ultimately this shows up in
the form of aggregated scheduled frequency deviations, or Time Error.
Does Inadvertent Interchange Relate to Reliability?
Short-term or limited accumulations of Inadvertent Interchange do not cause reliability issues
and are a part of normal interconnected operation in a multi-Balancing Authority Area
Interconnection.
With the evolution of industry, technical advancements in measurements, and more visibility of
the real-time operations, Inadvertent Interchange has little or no reliability impact. However,
large and long-held primary Inadvertent Interchange accumulations do impact commercial
relationships and their paybacks can create impacts to reliability if not conducted in an
appropriate manner.
Page | 1
Draft # 3 August 17, 2015
Causes of Inadvertent Interchange Accumulations
Some of the most common causes of Inadvertent Interchange are:
1) data recording errors;
2) metering errors;
3) scheduling errors;
4) ramping representation errors;
5) intentional control adjustments (temporary frequency support, smoothing algorithms,
and ACE filter gain factors); and,
6) unintentional control errors (from both human action and Automatic Generation
Control (AGC) errors);
Data Recording Errors
Simple data recording errors (incorrect value or sign) made while recording Actual Net
Interchange or Scheduled Net Interchange can become operating reliability problems,
depending upon the magnitude of the error, if they become a part of the Reporting ACE
calculation. When viewed from the Interconnection perspective, if the sum of all Balancing
Authority Areas’ Inadvertent Interchange accumulations no longer sum to zero due to these
data errors, frequency will be driven high or low, depending on the direction of the imbalance.
If not resolved, imbalances due to data errors show up in the form of recurring Time Error.
Other sources of error with Actual Net Interchange or Scheduled Net Interchange are identified
in the following paragraphs.
Metering Errors
All Tie Lines between Adjacent Balancing Authority Areas should reflect the same coincident
values at all times. Adjacent Balancing Authorities sharing a common tie are expected to use
common metering with a synchronized freeze at hour-end. This is intended to assure that both
Balancing Authorities capture the same value from the meter’s register or accumulators.
However, errors can occur due to the loss of telemetry by one or both Balancing Authority
Areas or in the difference between an integrated analog value being used by one party and a
megawatt-hour meter value being used by the other party. Another error may be created when
two Adjacent Balancing Authority Areas use different scaling factors. These errors should be
addressed through the requirements of the proposed BAL-005-1 and calculation of Reporting
ACE, since it requires that hour-ending values be equal but opposite direction between
Adjacent Balancing Authority Areas. It is important to note that, with respect to common
metering, the requirement under currently-effective BAL-006-2 regarding a Balancing
Authority’s obligation to ensure that all of its Balancing Authority Area interconnection points
are equipped with common megawatt hour meters has been moved to proposed BAL-005-1 at
Requirements R1 and R8.
Scheduling Errors
All Interchange Schedules between Adjacent Balancing Authorities should reflect the same
value with opposite direction. Errors can occur due to improper entry of data (time, amount,
direction, duration, etc.) or improper updates in real-time. While these errors may occur, it is
Page | 2
Draft # 3 August 17, 2015
not acceptable for two Balancing Authorities to knowingly operate to dissimilar Schedules (“to
agree to disagree”). These types of errors should be addressed through the requirements of the
proposed BAL-005-1 and calculation of Reporting ACE.
Ramping Representation Errors - Accounting Anomaly
The practice of using block (contract) Scheduled Net Interchanges instead of integrated
Scheduled Net Interchanges (the ramping effect) and subtracting the block values from
integrated Actual Net Interchange creates a “built-in” false error. Longer duration ramps have
the potential to produce larger errors. This is a false error because it gives the perception that
an error occurred when, in fact, the Balancing Authority may have had perfect control and, yet,
Inadvertent Interchange was created. These types of errors should be addressed through the
requirements of the proposed BAL-005-1 and calculation of Reporting ACE.
Intentional Control Errors – Frequency Support [expected]
Frequency continually changes as system load or generation changes. Balancing Authority
Areas have a responsibility to support frequency by acting in opposition to these changes.
When measured frequency is different than the Scheduled Frequency (due to Demand changes
or generation change) Balancing Authority Areas throughout an Interconnection adjust
dispatch to arrest the frequency changes and support frequency until it is restored to its
Scheduled value, in accordance with BAL-001, BAL-002, and BAL-003. During this period
each Balancing Authority Area adjusts its resources to create more or less energy than is
needed to serve its area Demand in order to support frequency, thus creating Inadvertent
Interchange. In contrast to previous errors, intentional control errors are created by other
standard requirements as opposed to being mitigated by them.
Unintentional Control Errors [unexpected]
If a Balancing Authority has insufficient regulating resources committed to follow its Demand
variability and provide frequency support, Inadvertent Interchange may result. Poor control
algorithms, generation outages, or generation deviation from Scheduled output could also
cause Inadvertent Interchange to accumulate.
Further, unintentional control errors are inherently created with the most basic physical model
of power generation, namely system inertia. A generating unit is unable to follow load with
absolute precision due to the amount of energy that is required to change a generating units
output and the instantaneous nature of load pickup that can occur. As load on the system
changes, Balancing Authorities are varying their generation levels to meet this load, and a
generator cannot follow a load with exact precision. The aggregation of these small
differences in generation and load balance can create inadvertent energy on the system.
Finally, an incorrectly calibrated frequency meter will send a false indication to a Balancing
Authority Area’s AGC causing it to operate uncoordinated with other Balancing Authority
Areas in the Interconnection. This will result in Inadvertent accumulations for the Balancing
Authority Area with the erroneous frequency input and unwanted accumulations by other
Balancing Authority Areas in the Interconnection. However, the proposed BAL-005-1 should
limit the impacts of incorrectly calibrated frequency meters.
Page | 3
Draft # 3 August 17, 2015
Since the BAL Standards all require the Balancing Authorities to calculate ACE in accordance
with the definitions, and within these Standards, there are requirements to mitigate errors used
in the calculation of ACE, the resulting Inadvertent should be caused by the generation
physically not being able to follow the precise electrical demands of the system.
Inadvertent Interchange
Inadvertent is zero for an hour when the Actual Net Interchange is equal to the Scheduled Net
Interchange for that hour. The goal of each Balancing Authority is to appropriately manage its
Inadvertent accumulations. Accomplishing this goal requires that settlement policies within their
Interconnection exist.
The retired NERC Policy 1F supported the short-term and long-term goals by stating: “Each
balancing authority shall be active in preventing unintentional Inadvertent Interchange
accumulations. Each Balancing Authority shall also be diligent in reducing accumulated
Inadvertent balances in accordance with Operating Policies.” This policy set no limits on the
amount of Inadvertent that could be accumulated or when it must have been paid back. This
policy was not a reliability policy, but was an accounting policy and should be resolved through
commercial means.
Interchange Accounting
1.
Accounting of Interchange. Accounting of energy between Balancing Authorities
residing within the same Interconnection is both simple and complicated. In theory,
Inadvertent Interchange is the difference between Actual Net Interchange and the
Scheduled Net Interchange over a given period, usually an hour. Mathematically, it is the
time integral of the deviation of a Balancing Authority's Actual Net Interchange from its
Scheduled Net Interchange:
NI I = NI A - NI S
Where,
NII is Inadvertent Interchange. In accordance with NERC convention, negative values of
Inadvertent Interchange denote a condition of importing energy or under-generation and
positive values denote exporting energy or over-generation.
NIA is Actual Net Interchange. It is the algebraic sum of the hourly integrated energy on
a Balancing Authority's Tie Lines including Pseudo-ties. Actual Net Interchange is
positive for power leaving the system and negative for power entering it.
NIS is Scheduled Net Interchange. It is defined as the mutually prearranged net energy on
a Balancing Authority’s Tie Lines including Dynamic Schedules or fixed Schedules for
any jointly owned or contracted generation. The Scheduled Net Interchange is positive
Page | 4
Draft # 3 August 17, 2015
for power scheduled to be delivered from the Balancing Authority Area and negative for
power Scheduled to be received into the Balancing Authority Area.
2.
Actual Net Interchange Energy Accounting. Actual Net Interchange (metered
interchange) between two Adjacent Balancing Authority Areas over a common Tie Line
is accounted for at a specific point in the line. Furthermore, both Balancing Authorities
shall agree on the amount of energy flow through this point, including any Pseudo-Tie
flows that may exist between the two Balancing Authority Areas. Therefore, the sum of
metered energy accounted by both Balancing Authority Areas over this Tie Line nets to
zero. Since this is true for all Balancing Authority Areas within the same
Interconnection, the algebraic sum of all metered energy within the same Interconnection
is also zero.
3.
Scheduled Net Interchange Energy Accounting. All Interchange Schedules shall have
an agreed-upon Interchange Transaction size (megawatts), a start and end time, a
beginning and ending ramp time and rate, and type required for delivery and receipt of
power and energy between the Source and Sink Balancing Authorities involved in the
transaction. Dynamic Schedules and fixed Schedules for jointly owned or contracted
generation between Balancing Authority Areas should be agreed to on an hour-by-hour
basis, and included in the Scheduled Net Interchange of both Balancing Authority Areas.
The algebraic sum of Scheduled Net Interchange accounted by both Balancing Authority
Areas must equal zero. Since every Interchange Schedule is agreed to by all involved
delivering and receiving Balancing Authority Areas within an Interconnection, the
algebraic sum of all Scheduled Net Interchange is also zero.
4.
Inadvertent Interchange Energy Accounting. As stated previously, Inadvertent
Interchange is the difference between Actual Net Interchange and Scheduled Net
Interchanges over a given period. Since the algebraic sum of all Actual Net Interchange
and the algebraic sum of all Scheduled Net Interchanges for any given period is zero
within an Interconnection, the sum of all inadvertent interchange is also zero.
When Reporting ACE is properly implemented according to principles 2 and 3 included in the
NERC definition, the above four conditions will result. This balancing of Inadvertent energy
accounting allows effective payback methods to be implemented.
Inadvertent Interchange Energy Accounting Practices
The practices set forth in this section outline the methods required to reconcile energy accounting
and inadvertent interchange balances.
For a Balancing Authority Area to properly monitor and account for Inadvertent Interchange, all
Balancing Authority Areas must follow the same methodology within that Interconnection.
1.
Page | 5
Accounting Procedures
Draft # 3 August 17, 2015
2.
1.1.
On-Peak and Off-Peak Accounting Periods. Each Balancing Authority is
obligated to maintain its Inadvertent Interchange accounting within two periods,
namely, On-Peak and Off-Peak.
1.2.
Interchange Schedules. All hourly Schedules and Schedule changes shall be
agreed upon between the Balancing Authority Areas involved prior to
implementation in regard to common magnitude, rate of change, starting time, and
ending time.
1.3.
Dynamic Schedules. Dynamic Schedules integrated on an hourly basis shall be
agreed upon by the Balancing Authority Areas involved subsequent to the hour,
but in such a manner as not to impact Inadvertent accounts. This is accomplished
by assuring that the hourly actual and scheduled Interchange quantities agree
between all delivering and receiving parties.
1.4.
Daily Accounting. Each Balancing Authority shall agree with its Adjacent
Balancing Authority Area as to the hourly values of actual Interchange (megawatt
hour) scheduled interchange (megawatt hour) for On-Peak and Off-Peak periods.
1.5.
Monthly Accounting. Having agreed to the On-Peak and Off-Peak period hourly
values on a daily basis, Balancing Authorities should expect the summation of
accumulated values for the month to balance to zero for each Interconnection.
1.6.
Adjustments for Error. Adjustments shall be made each month to correct for
differences between hourly megawatt hour meter totals and the hourly integrated
totals derived from register readings at the Tie Line meters.
1.6.1
Differences. Adjacent Balancing Authorities shall agree upon the
difference determined above and assign this correction to the proper
On-Peak and Off-Peak period and in equal quantities in the opposite
directions.
1.6.2
Adjustments. Adjustments necessary due to known metering errors,
franchised territories, transmission losses or other special circumstances
shall be made in the same manner as 1.6.1.
NAESB Standard WEQ-007 Business Practices Requirements:
2.1. Inadvertent Interchange payback. Each Balancing Authority shall be diligent in reducing
Inadvertent Interchange accumulations. Balancing Authorities shall payback Inadvertent
Interchange accumulations by one of the following methods:
2.1.1. Energy “in-kind” payback. Inadvertent Interchange accumulated during “On-Peak”
hours shall only be paid back during “On-Peak” hours. Inadvertent Interchange
accumulated during “Off-Peak” hours shall only be paid back during “Off-Peak”
hours.
Page | 6
Draft # 3 August 17, 2015
2.1.1.1. Bilateral payback. Inadvertent Interchange accumulations may be paid back
via an Interchange Schedule with another Balancing Authority.
2.1.1.1.1. Opposite balances. The Source Balancing Authority Area and Sink
Balancing Authority Area must have Inadvertent Interchange
accumulations in the opposite direction.
2.1.1.1.2. Payback terms. The terms of the Inadvertent Interchange payback shall
be agreed upon by all involved Balancing Authorities and Transmission
Service Providers.
2.1.1.2. Unilateral payback. Inadvertent Interchange accumulations may be paid back
unilaterally controlling to a target of non-zero ACE. Controlling to a nonzero
ACE ensures that the unilateral payback is accounted for in the CPS1
calculations. The unilateral payback control offset is limited to Balancing
Authority Areas‘ L10 limit and shall not burden the Interconnection.
2.1.2. Other payback methods. Upon agreement by all Regional entities within an
Interconnection, other methods of Inadvertent Interchange payback may be utilized.
The Western Interconnection established a regional reliability standard BAL-004WECC-02 – Automatic Time Error Correction in which Primary Inadvertent
Interchange payback are effectively conducted in a manner that does not adversely
affect the reliability of the Interconnection.
2.1.3. Implementation of the following Reporting ACE equation by all Regions entities
within an Interconnection would result in automatic Inadvertent payback for that
interconnection independent of Time Error Correction as implemented on the
Western Interconnection.
Reporting ACE = (NIA í NIS) í 10B (FA í FS) í IME + IAIP
Where:
IAIP (Automatic Inadvertent Payback) is the addition of a component to the
Reporting ACE equation that modifies the control point for the purpose of
continuously paying back Inadvertent Interchange to correct accumulated
Inadvertent accounts without correcting for Time Error.
Τࢌࢌࢋࢇ
ۯ۷۾
ൌ ࢇࢉࢉ࢛
۶
when operating in Automatic Inadvertent Payback mode.
The absolute value of IAIP shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
x
x
Page | 7
Lmax is the maximum value allowed for IAIP set by each BAA between 0.2*|Bi| and L10, 0.2
*|Bi| Lmax L10 .
L10 ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ .
Draft # 3 August 17, 2015
x
x
x
x
x
x
H10 is a constant derived from the targeted frequency bound. It is the targeted rootmean-square (RMS) value of ten-minute average frequency error based on frequency
performance over a given year. The bound, H10, is the same for every Balancing
Authority Area within an Interconnection.
H = Number of hours used to payback Inadvertent Interchange energy.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW / 0.1
Hz).
Inadvertent Interchange is IIactual is the hourly Inadvertent Interchange for the last hour.
IIaccum is the Balancing Authority Area’s accumulated IIactual in MWh. An On-Peak and
Off-Peak accumulation accounting is required,
where:
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࢇࢉ࢚࢛ࢇ
Implementation of Automatic Inadvertent Payback as shown above would also
require a modification to the Reporting ACE definition in the NERC Glossary to
allow for its implementation in the Reporting ACE equation.
3.
Inadvertent Interchange over Direct Current Tie Lines between Separately
Synchronous Interconnections
For the purpose of NERC inadvertent interchange calculations, there shall be no
contribution to a Balancing Authority’s Reporting ACE or Inadvertent accumulation due
to a direct current tie connecting Adjacent Balancing Authorities operating in separate
Interconnections.
4.
5.
Summary of Accounting Rules
4.1.
Summation of Interchange Schedules. The summation of all Interchange
Schedules within an Interconnection shall total zero for any period of time.
4.2.
Summation of Actual Net Interchange. The summation of all Actual Net
Interchange within an Interconnection shall total zero for any period of time.
4.3.
Summation of inadvertent interchange for Interconnection. The summation
of all Inadvertent Interchange within an Interconnection shall total zero for any
period of time.
Accounting Examples
Daily, total Net Actual Interchange for each hour accumulated during the On-Peak and
Off-Peak periods. Do the same with the Scheduled Net Interchanges. By period, subtract
the totaled Scheduled Net Interchange from the totaled Actual Net Interchange. This will
yield On-Peak and Off-Peak Inadvertent accumulations for the day. The addition of these
two accumulations is the Balancing Authority’s Inadvertent Interchange accumulation for
Page | 8
Draft # 3 August 17, 2015
the day. All Balancing Authorities must keep an accurate, continuous record of their
current balances of On-Peak, Off-Peak, and (net) Inadvertent for the day, month, and
accumulative to date, to meet accounting requirements
Need for a Reliability Standard
It is recognized that Tie Line Bias operation results in the creation of Inadvertent Interchange.
The need for action required for reliable system operation is reflected in the requirements in the
proposed BAL-005-1. Actions to resolve potential reliability problems associated with
Inadvertent is addressed in the BAL-005 requirements. Inadvertent accumulation is an equity
issue that cannot be solved with a reliability requirement.
NERC Reliability Standards are based on principles that define the foundation of reliability for
the North American Bulk Electric System. Each Standard enables or supports one or more of
these principles, thereby ensuring that each Reliability Standard serves a purpose in support of
reliability of the North American Bulk Electric System.
Even though FERC Order 693 directs the ERO to develop modifications to BAL-006 to add
requirements to address certain issues associated with Inadvertent, Inadvertent accumulation
does not cause the Interconnection to be unreliable. However, if a Balancing Authority Area’s
Inadvertent accumulation is extremely large, it may drive most of the other accumulations held
by other Balancing Authority Areas in the Interconnection to become uncomfortably large in the
opposite direction. This may drive unilateral paybacks resulting in a topological shift in
transmission loadings to the point of becoming a reliability problem. Normally, there is no
reliability issue associated with Inadvertent.
The proposed BAL-005-1 requirements, along with the requirements of BAL-001, BAL-002, and
BAL-003, establish the reliability requirements for Balancing Authorities to ensure that a
Balancing Authority does not excessively depend on other Balancing Authorities in the
Interconnection to meet their Demand or Interchange obligations.
The NERC Resources Subcommittee and Inadvertent Interchange Working Group, which serve
at the pleasure of the NERC Operating Committee, will continue to monitor Inadvertent
Interchange, in conjunction with the aforementioned suite of balancing Reliability Standards, to
ensure that Inadvertent accumulations do not result in adverse impacts on reliability.
FERC Order No. 693 was issued prior to other changes in the industry, such as the modified
BAL-001-2 and the new BAL-003-1, along with the work on BAL-002-2 and the proposed
BAL-005-1. All of these changes are designed to ensure that Balancing Authority Areas do not
excessively depend on other Balancing Authority Areas in the Interconnection to meet their
Demand obligations. Some of the changes are designed to allow for Inadvertent while
supporting Interconnection frequency and reducing the need to move generation in one direction
or the other (over-generating or under-generating). To allow for these changes, while enhancing
reliability, the drafting team is proposing a commercial method to resolve Inadvertent while
accommodating the requirements of Order 693. In light of other requirements and proposed
requirements under the BAL Reliability Standards, the drafting team is recommending a
Page | 9
Draft # 3 August 17, 2015
commercial requirement rather than a reliability requirement. The Commission has already
established such a procedure when handling imbalance charges within the Open Access Tariffs.
Commercial Requirement
If all the requirements within proposed BAL-005-1 are met continuously by the Balancing
Authority Areas, reliability requirements are met and thus Inadvertent Interchange accumulations
are a commercial issue.
A commercial requirement is necessary to:
1) Establish a tracking mechanism for Inadvertent Interchange accumulations (currently
provided through CERTS Inadvertent application), and
2) Encourage settlements within a reasonable time period.
These reasons are explained in the following paragraphs.
Quality Control
Inadvertent data requires the ability to measure the accuracy and effectiveness of meters,
scheduling systems, and energy management systems, as indicated in the requirements of the
proposed BAL-005-1. As such, it provides a check and balance for the measurement
systems.
Data Accuracy
Inadvertent data requires that all Balancing Authority Areas within an Interconnection have
accurate data for timely management of Inadvertent accumulations and a process for
reducing accumulated Inadvertent balances.
Diagnostic Tool to Validate Performance
Inadvertent Interchange is a source of independent data for diagnostic purposes as
recommended by the U.S.-Canada Power System Outage Task Force. NERC Reliability
Standards BAL-001. BAL-002, and BAL-003 are used to evaluate Balancing Authority
reliability performance.
The proposed Reliability Standard BAL-005-1 contains requirements for a system operator to
examine real-time system inputs to determine if a metering problem exists, a Schedule is
incorrectly entered, or the frequency indication is erroneous.
From an Interconnection viewpoint, Inadvertent accumulations over a given time period
(e.g., several months) can occur without making an Interconnection unreliable. An
Interconnection may have operated within the prescribed safe frequency range; however, one
Balancing Authority Area may have been over-generating, while another was undergenerating. Thus the Interconnection was reliable and balanced. The resulting accumulated
Inadvertent becomes an equity issue.
Tracking Mechanism for Accumulations
Page | 10
Draft # 3 August 17, 2015
Since Inadvertent always sums to zero for an Interconnection, every megawatt hour of positive
Inadvertent held by one Balancing authority area is balanced with a megawatt hour of negative
Inadvertent held by another. Therefore, a Balancing Authority Area holding an amount of
Inadvertent accumulation forces other Balancing Authority Areas to hold a collective amount
of Inadvertent accumulation in the opposite direction.
Balancing Authority Areas should track their accumulations of Inadvertent Interchange to
assure equity among the Balancing Authority Areas within the Interconnection is maintained.
Monthly and accumulated Inadvertent Interchange balances are presently tracked and
reported via a CERTS Inadvertent Interchange Reporting Application. This reporting process
should be maintained to insure that accurate Inadvertent balances are recorded and available
for analysis.
Reasonable Time Limit for Settling Accumulations
While the retired NERC Policy 1F encourages Balancing Authorities to “be diligent in
reducing accumulated Inadvertent balances”, it does not indicate the time period that these
reductions must occur. Is it acceptable to hold accumulated Inadvertent balances for years?
Inadvertent Interchange Payback Schemes
An Inadvertent Interchange accumulation means that demands in the Balancing Authority Area
with a negative accumulation of Inadvertent interchange are in part supplied off-schedule by
generators in the other Balancing Authority Areas. Symmetrically, generators in an area with a
positive accumulation of Inadvertent interchange supply Demands in some other areas offschedule. Effectively, the Inadvertent Interchange accumulation means systematic overgeneration or under-generation in the corresponding Balancing Authority Area. This economic
imbalance can be settled either through the financial mechanisms, or unilateral or bilateral
Inadvertent interchange payback schemes discussed previously. However, any commercial
mechanism must be an agreed to and coordinated scheme and applied equally to everyone within
the Interconnection. If any Balancing Authority does something different than what has been
agreed for the Interconnection, then a reliability problem may arise.
Options
Unilateral Payback Schemes
In the unilateral payback scheme, a Balancing Authority Area unilaterally and intentionally overgenerates or under-generates over a certain time interval, in accordance with an agreed upon
process or NAESB standard, to pay the corresponding negative or positive Inadvertent
Interchange accumulation back to the Interconnection. This scheme can be automated as it is
done in the Western Interconnection through the Reliability Standard BAL-004-WECC-02.
Bilateral Payback Schemes
In the bilateral scheme, two Balancing Authority areas, one with a positive and one with a
corresponding negative Inadvertent Interchange accumulation, agree upon the time and the size
of a scheduled inadvertent Interchange payback. Unlike the unilateral Inadvertent Interchange
Page | 11
Draft # 3 August 17, 2015
payback, this scheme must be balanced and not impact the Interconnection active power balance
or Interconnection frequency.
Automatic Payback Schemes
In an Automatic Payback scheme as described in 2.1.3 of this document, all Balancing
Authorities in an Interconnection agree to “payback” the same proportion of their accumulated
Inadvertent in each hour. Since the accumulated Inadvertent on and off peak accounts are
balanced, the resulting Reporting ACE adjustments would also be balanced and have no
reliability effect on the Interconnection active power balance or Interconnection frequency.
The payback procedures must be conducted separately for the on-peak and off-peak hours.
Financial Settlement
With a financial settlement mechanism, a price must be established for each Interconnection.
One could equate a financial settlement to the current imbalance charges within entities Open
Access Transmission Tariffs (OATT). The OATTS provisions settle under and over-generation
for the specific Balancing Authority Areas through a specific price while maintaining the
reliability of the Interconnection. Inadvertent is an imbalance for the Interconnection. A
commercial price could be established for the Interconnection, where the over-generating
Balancing Authority area would receive a payment while the under-generating Balancing
Authority Area would pay.
The commercial price for each Interconnection could be established through a FERC process or
through a NAESB process. However, the commercial rules and procedures should be clear and
defined.
The financial arrangements could be administered through a third party established by FERC for
the Interconnection. Rules would need to be established on various issues, such as timing, the
amount of inadvertent a Balancing Authority area could accumulate over a given period, and
others. However, one could use the current OATT imbalance charge process as a guideline to
establish such a financial settlement for Inadvertent.
Page | 12
Unofficial Survey Form
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls: Inadvertent Interchange
BAL-006
DO NOT use this form for submitting survey responses. Use the electronic form to submit survey
responses on Project 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls: Inadvertent
Interchange (BAL-006). Responses must be submitted by 8 p.m. Eastern, Friday, September 25, 2015.
Documents and information about this project are available on the project page. If you have questions,
contact Senior Standards Developer, Darrel Richardson (via email), or at (609) 613-1848.
Background Information
This Project 2010-14.2.1 Phase 2 Balancing Authority Reliability-based Controls standard drafting team
(SDT) is soliciting comments from the industry concerning the disposition of BAL-006. The Independent
Expert Review Report, Periodic Review Team, and (during the SAR comment phase) industry indicated
that majority of currently-effective Reliability Standard BAL-006-2 as written is an energy accounting
standard and not a Reliability Standard.
The Federal Energy Regulatory Commission (“Commission”) recommended the development of a metric
to bind the magnitude of inadvertent accumulations, as those accumulations may be indicative of a
Balancing Authority excessively leaning on the resources of others in its Interconnection. The SDT
consensus was that an Inadvertent Interchange accumulation value alone cannot yield useful information
concerning whether a Balancing Authority is operating reliably. The SDT has proposed revisions to BAL005, and, the SDT believes that with these revisions and the other suite of BAL Standards, the Reliability
Standards address reliable operation of Balancing Authorities.
Thus, with the evolution of the industry, technical advancements in measurements, and more visibility of
the real-time operations, Inadvertent Interchange has little or no impact on reliability. However, large
and long-held Inadvertent Interchange accumulations do impact commercial relationships, and their
paybacks can create impacts to reliability if they are not conducted appropriate manner. This is discussed
in a white paper being posted contemporaneously with this survey.
Questions
1. Based on comments related to the SAR, the Independent Expert Review Report, and the Periodic
Review Team’ recommendations, the industry agrees that BAL-006 is an energy accounting standard
and not a Reliability Standard, however, it is unclear what the industry supports as a replacement.
The SDT has developed a white paper for the industry to consider. Based on the concepts within the
white paper, do you support maintaining Reliability Standard BAL-006? 1
Modify and maintain BAL-006 as a Reliability Standard.
Maintain BAL-006 (with no changes) as a Reliability Standard.
Eliminate BAL-006 as a Reliability Standard.
Comments:
2. If you support maintaining BAL-006 as a Reliability Standard, are you in favor of the PRT
recommendation as noted in the attached draft Reliability Standard BAL-006? If not, then what
aspects of BAL-006 should be retained in a standard?
Yes:
No:
Comments:
3. If you support eliminating BAL-006 as a Reliability Standard, are you in favor of the SDT
recommendation that these requirements be included in a commercial alternative arrangement, such
as a NAESB standard or a process established by FERC? What aspects of BAL-006 should be retained
in an alternative arrangement?
Yes:
No:
Comments:
4. If neither maintaining nor eliminating BAL-006 is preferred, please describe your suggestion for the
disposition of this standard.
Comments:
1
When responding to this survey and providing comments, please keep in mind that draft proposed Reliability Standard BAL-006-3
has been posted under 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls, in connection with draft proposed Reliability
Standards BAL-005-1 and FAC-001-3. Proposed Reliability Standard BAL-005-1, at Requirements R1 and R8, would include the obligations
currently under Requirement R3 of Reliability Standard BAL-006-2.
Unofficial Survey Form
Project 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls: Inadvertent Interchange
2
5. If you have any other comments or reliability concerns, please provide them in the space below.
Comments:
Unofficial Survey Form
Project 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls: Inadvertent Interchange
3
Standard BAL-006-XX — Inadvertent Interchange DRAFT
A.
Introduction
1.
Title:
Inadvertent Interchange
2.
Number:
BAL-006-XX
3.
Purpose:
This standard defines a process for monitoring Balancing Authorities to ensure that, over the
long term, Balancing Authority Areas do not excessively depend on other Balancing Authority
Areas in the Interconnection for meeting their demand or Interchange obligations.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
First day of first calendar
quarter after applicable regulatory approval, or
in those jurisdictions where no regulatory
approval is required, first day of first calendar
quarter after Board of Trustees adoption.
Note that as the revisions proposed for BAL-006
focus on the minimum requirements for Adjacent
Balancing Authorities to agree upon the hourly MW
amounts of scheduled and actual Interchange between
them, which reinforces that errors in coordination or
process will be identified, the PRT recommends that
the SDT revise the Purpose statement to be consistent
with the Requirements as further developed under the
SAR posted with this proposed redline.
Requirements
R1. Each Balancing Authority shall agree with its Adjacent Balancing Authorities by the end of
the next business day on: (Violation Risk Factor: Lower)
R1.1. The hourly values of Net Interchange Schedule. (Violation Risk Factor: Lower)
R1.2. The hourly integrated megawatt-hour values of Net Actual Interchange. (Violation Risk
Factor: Lower)
R2. Each Balancing Authority shall use the agreed-to daily and monthly accounting data to
compile its monthly accumulated Inadvertent Interchange for the On-Peak and Off-Peak hours
of the month. (Violation Risk Factor: Lower)
R3. Each Balancing Authority shall make after-the-fact corrections to the agreed-to daily and
monthly accounting data only as needed to reflect actual operating conditions (e.g. a meter
being used for control was sending bad data). Changes or corrections based on non-reliability
considerations shall not be reflected in the Balancing Authority’s Inadvertent Interchange.
After-the-fact corrections to scheduled or actual values will not be accepted without
agreement of the Adjacent Balancing Authority(ies). (Violation Risk Factor: Lower)
R4. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual
Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following
month shall, for the purposes of dispute resolution, submit a report to their respective Regional
Reliability Organization Survey Contact.
R4.1. The report shall describe the nature and the cause of the dispute as well as a process for
correcting the discrepancy. (Violation Risk Factor: Lower)
C.
Measures
None specified.
D.
Compliance
1.
Compliance Monitoring Process
1
Standard BAL-006-XX — Inadvertent Interchange DRAFT
1.1.
Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.
These summaries shall not include any after-the-fact changes that were not agreed to
by the Source Balancing Authority, Sink Balancing Authority and all Intermediate
Balancing Authority(ies).
1.2.
Inadvertent Interchange summaries shall include at least the previous accumulation, net
accumulation for the month, and final net accumulation, for both the On-Peak and OffPeak periods.
1.3.
Each Balancing Authority shall submit its monthly summary report to its Regional
Reliability Organization Survey Contact by the 15th calendar day of the following
month.
1.4.
Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as
requested by the NERC Operating Committee to determine the Balancing Authority’s
Interchange error(s) due to equipment failures or improper scheduling operations, or
improper AGC performance.
1.5.
Each Regional Reliability Organization shall prepare a monthly Inadvertent
Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent
Interchange and all-time accumulated Inadvertent Interchange. Each Regional
Reliability Organization shall submit a monthly accounting to NERC by the 22nd day
following the end of the month being summarized.
2
N/A
N/A
N/A
The Balancing Authority failed to
record Actual Net Interchange
values that are equal but opposite
in sign to its Adjacent Balancing
Authorities.
N/A
R2.
R3.
R4.
R4.1.
Lower VSL
Violation Severity Levels
R1.
R#
2.
N/A
The Balancing Authority failed to
compute Inadvertent Interchange.
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
Failed to take into account
interchange served by jointly
owned generators.
Failed to take into account
interchange served by jointly
owned generators.
N/A
The Balancing Authority failed to
operate to a common Net
Interchange Schedule that is equal
but opposite to its Adjacent
Balancing Authorities.
3
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
N/A
The Balancing Authority failed to
ensure all of its Balancing
Authority Area interconnection
points are equipped with common
megawatt-hour meters, with
readings provided hourly to the
control centers of Adjacent
Balancing Authorities.
AND
OR
N/A
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
Each Balancing Authority failed to
calculate and record hourly
Inadvertent Interchange.
Severe VSL
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
N/A
High VSL
N/A
N/A
N/A
N/A
R4.1.1.
R4.1.2.
R4.2.
R4.3.
R#
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
N/A
N/A
N/A
N/A
High VSL
4
The Balancing Authority failed to
make after-the-fact corrections to
the agreed-to daily and monthly
accounting data to reflect actual
operating conditions or changes or
corrections based on non-reliability
considerations were reflected in the
The Balancing Authority failed to
use the agreed-to daily and
monthly accounting data to
compile its monthly accumulated
Inadvertent Interchange for the OnPeak and Off-Peak hours of the
month.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
integrated megawatt-hour values of
Net Actual Interchange.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
The hourly integrated megawatthour values of Net Actual
Interchange.
AND
values of Net Interchanged
Schedule.
Severe VSL
R5.
R#
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities, submitted a
report to their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute but failed
to provide a process for correcting
the discrepancy.
Lower VSL
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities by the 15th
calendar day of the following
month, failed to submit a report to
their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute as well as a
process for correcting the
discrepancy.
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
N/A
High VSL
N/A
5
Balancing Authority’s Inadvertent
Interchange.
Severe VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
E.
Regional Differences
1.
Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March
25, 2004includes SPP effective May 1, 2006.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
April 6, 2006
Added following to “Effective Date:” This
standard will expire for one year beyond the
effective date or when replaced by a new version
of BAL-006, whichever comes first.
Errata
2
November 5, 2009
Added approved VRFs and VSLs to document.
Revision
Removed MISO from list of entities with an
Inadvertent Interchange Accounting Waiver
(Project 2009-18).
2
November 5, 2009
Approved by the Board of Trustees
2
January 6, 2011
Approved by FERC
6
Standard BAL-006-XX — Inadvertent Interchange DRAFT
A.
Introduction
1.
Title:
Inadvertent Interchange
2.
Number:
BAL-006-XX
3.
Purpose:
This standard defines a process for monitoring Balancing Authorities to ensure that, over the
long term, Balancing Authority Areas do not excessively depend on other Balancing Authority
Areas in the Interconnection for meeting their demand or Interchange obligations.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
First day of first calendar
quarter after applicable regulatory approval, or
in those jurisdictions where no regulatory
approval is required, first day of first calendar
quarter after Board of Trustees adoption.
Note that as the revisions proposed for BAL-006
focus on the minimum requirements for Adjacent
Balancing Authorities to agree upon the hourly MW
amounts of scheduled and actual Interchange between
them, which reinforces that errors in coordination or
process will be identified, the PRT recommends that
the SDT revise the Purpose statement to be consistent
with the Requirements as further developed under the
SAR posted with this proposed redline.
Requirements
R1. Each Balancing Authority shall calculate and record hourly Inadvertent Interchange.
(Violation Risk Factor: Lower)
R2. Each Balancing Authority shall include all AC tie lines that connect to its Adjacent Balancing
Authority Areas in its Inadvertent Interchange account. The Balancing Authority shall take
into account interchange served by jointly owned generators. (Violation Risk Factor: Lower)
R3. Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection
points are equipped with common megawatt-hour meters, with readings provided hourly to the
control centers of Adjacent Balancing Authorities. (Violation Risk Factor: Lower)
R4. Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and
Actual Net Interchange value and shall record these hourly quantities, with like values but
opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange based on
the following: (Violation Risk Factor: Lower)
R5.R1. Each Balancing Authority, by the end of the next business day, shall agree with its
Adjacent Balancing Authorities by the end of the next business day toon: (Violation Risk
Factor: Lower)
R5.1.R1.1. The hourly values of Net Interchange Schedule. (Violation Risk Factor: Lower)
R5.2.R1.2.
The hourly integrated megawatt-hour values of Net Actual Interchange.
(Violation Risk Factor: Lower)
R6.R2. Each Balancing Authority shall use the agreed-to daily and monthly accounting data to
compile its monthly accumulated Inadvertent Interchange for the On-Peak and Off-Peak hours
of the month. (Violation Risk Factor: Lower)
R7.R3. AEach Balancing Authority shall make after-the-fact corrections to the agreed-to daily
and monthly accounting data only as needed to reflect actual operating conditions (e.g. a meter
being used for control was sending bad data). Changes or corrections based on non-reliability
considerations shall not be reflected in the Balancing Authority’s Inadvertent Interchange.
After-the-fact corrections to scheduled or actual values will not be accepted without
agreement of the Adjacent Balancing Authority(ies). (Violation Risk Factor: Lower)
1
Standard BAL-006-XX — Inadvertent Interchange DRAFT
R4. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual
Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following
month shall, for the purposes of dispute resolution, submit a report to their respective Regional
Reliability Organization Survey Contact.
R7.1.R4.1. The report shall describe the nature and the cause of the dispute as well as a
process for correcting the discrepancy. (Violation Risk Factor: Lower)
C.
Measures
None specified.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.
These summaries shall not include any after-the-fact changes that were not agreed to
by the Source Balancing Authority, Sink Balancing Authority and all Intermediate
Balancing Authority(ies).
1.2.
Inadvertent Interchange summaries shall include at least the previous accumulation, net
accumulation for the month, and final net accumulation, for both the On-Peak and OffPeak periods.
1.3.
Each Balancing Authority shall submit its monthly summary report to its Regional
Reliability Organization Survey Contact by the 15th calendar day of the following
month.
1.4.
Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as
requested by the NERC Operating Committee to determine the Balancing Authority’s
Interchange error(s) due to equipment failures or improper scheduling operations, or
improper AGC performance.
1.5.
Each Regional Reliability Organization shall prepare a monthly Inadvertent
Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent
Interchange and all-time accumulated Inadvertent Interchange. Each Regional
Reliability Organization shall submit a monthly accounting to NERC by the 22nd day
following the end of the month being summarized.
2
N/A
N/A
N/A
The Balancing Authority failed to
record Actual Net Interchange
values that are equal but opposite
in sign to its Adjacent Balancing
Authorities.
N/A
R2.
R3.
R4.
R4.1.
Lower VSL
Violation Severity Levels
R1.
R#
2.
N/A
The Balancing Authority failed to
compute Inadvertent Interchange.
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
Failed to take into account
interchange served by jointly
owned generators.
Failed to take into account
interchange served by jointly
owned generators.
N/A
The Balancing Authority failed to
operate to a common Net
Interchange Schedule that is equal
but opposite to its Adjacent
Balancing Authorities.
3
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
N/A
The Balancing Authority failed to
ensure all of its Balancing
Authority Area interconnection
points are equipped with common
megawatt-hour meters, with
readings provided hourly to the
control centers of Adjacent
Balancing Authorities.
AND
OR
N/A
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
Each Balancing Authority failed to
calculate and record hourly
Inadvertent Interchange.
Severe VSL
The Balancing Authority failed to
include all AC tie lines that
connect to its Adjacent Balancing
Authority Areas in its Inadvertent
Interchange account.
N/A
High VSL
N/A
N/A
N/A
N/A
R4.1.1.
R4.1.2.
R4.2.
R4.3.
R#
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
N/A
N/A
N/A
N/A
High VSL
4
The Balancing Authority failed to
make after-the-fact corrections to
the agreed-to daily and monthly
accounting data to reflect actual
operating conditions or changes or
corrections based on non-reliability
considerations were reflected in the
The Balancing Authority failed to
use the agreed-to daily and
monthly accounting data to
compile its monthly accumulated
Inadvertent Interchange for the OnPeak and Off-Peak hours of the
month.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
integrated megawatt-hour values of
Net Actual Interchange.
The Balancing Authority, by the
end of the next business day, failed
to agree with its Adjacent
Balancing Authorities to the hourly
values of Net Interchanged
Schedule.
The hourly integrated megawatthour values of Net Actual
Interchange.
AND
values of Net Interchanged
Schedule.
Severe VSL
R5.
R#
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities, submitted a
report to their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute but failed
to provide a process for correcting
the discrepancy.
Lower VSL
Adjacent Balancing Authorities
that could not mutually agree upon
their respective Net Actual
Interchange or Net Scheduled
Interchange quantities by the 15th
calendar day of the following
month, failed to submit a report to
their respective Regional
Reliability Organizations Survey
Contact describing the nature and
the cause of the dispute as well as a
process for correcting the
discrepancy.
Moderate VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
N/A
High VSL
N/A
5
Balancing Authority’s Inadvertent
Interchange.
Severe VSL
Standard BAL-006-XX — Inadvertent Interchange DRAFT
E.
Regional Differences
1.
Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March
25, 2004includes SPP effective May 1, 2006.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
April 6, 2006
Added following to “Effective Date:” This
standard will expire for one year beyond the
effective date or when replaced by a new version
of BAL-006, whichever comes first.
Errata
2
November 5, 2009
Added approved VRFs and VSLs to document.
Revision
Removed MISO from list of entities with an
Inadvertent Interchange Accounting Waiver
(Project 2009-18).
2
November 5, 2009
Approved by the Board of Trustees
2
January 6, 2011
Approved by FERC
6
Standards Announcement
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls: Inadvertent Interchange
BAL-006
Survey Being Conducted through September 25, 2015
Now Available
The Project 2010-14.2.1 Phase 2.1 Balancing Authority Reliability-based Controls standard drafting team
is soliciting comments from the industry concerning the disposition of BAL-006-2. The Independent
Expert Review Report, Periodic Review Team, and industry (during the SAR comment period) indicated
that majority of BAL-006-2 as written is an energy accounting standard and not a reliability standard.
However, it was unclear what exactly the industry desires to accommodate the need for energy
accounting. With the evolution of industry, technical advancements in measurements, and more visibility
of the real-time operations, Inadvertent Interchange has little or no reliability impact. However, large
and long-held Inadvertent Interchange accumulations do impact commercial relationships and their
paybacks can create impacts to reliability if not conducted in an appropriate manner. Responses must be
submitted by 8 p.m. Eastern, Friday, September 25, 2015.
Use the electronic form to submit survey responses. If you experience any difficulties in using the
electronic form, contact Wendy Muller.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at [email protected] (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email), or
at (609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
9/25/2015
End Date
Eliminate BAL-006 as a Reliability Standard.
Maintain BAL-006 (with no changes) as a Reliability Standard.
Modify and maintain BAL-006 as a Reliability Standard.
When responding to this survey and providing comments, please keep in mind that
[1]
draft proposed Reliability Standard BAL-006-3 has been posted under 2010-14.2.1 Phase 2 of
Balancing Authority Reliability-based Controls, in connection with draft proposed Reliability
Standards BAL-005-1 and FAC-001-3. Proposed Reliability Standard BAL-005-1, at Requirements
R1 and R8, would include the obligations currently under Requirement R3 of Reliability Standard
BAL-006-2.
1. Based on comments related to the SAR, the Independent Expert Review Report, and the
Periodic Review Team’ recommendations, the industry agrees that BAL-006 is an energy
accounting standard and not a Reliability Standard, however, it is unclear what the industry
supports as a replacement. The SDT has developed a white paper for the industry to
consider. Based on the concepts within the white paper, do you support maintaining Reliability
Standard BAL-006?[1]
Survey Questions
Associated Ballots
9/16/2015
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls: Inadvertent
Interchange | BAL-006 Survey
Start Date
Description
Name
Survey Details
Survey Report
Responses By Question
5. If you have any other comments or reliability concerns, please provide them in the space
below.
4. If neither maintaining nor eliminating BAL-006 is preferred, please describe your suggestion
for the disposition of this standard.
No
Yes
3. If you support eliminating BAL-006 as a Reliability Standard, are you in favor of the SDT
recommendation that these requirements be included in a commercial alternative arrangement,
such as a NAESB standard or a process established by FERC? What aspects of BAL-006 should
be retained in an alternative arrangement?
No
Yes
2. If you support maintaining BAL-006 as a Reliability Standard, are you in favor of the PRT
recommendation as noted in the attached draft Reliability Standard BAL-006? If not, then what
aspects of BAL-006 should be retained in a standard?
When responding to this survey and providing comments, please keep in mind that
[1]
draft proposed Reliability Standard BAL-006-3 has been posted under 2010-14.2.1 Phase 2 of
Balancing Authority Reliability-based Controls, in connection with draft proposed Reliability
Standards BAL-005-1 and FAC-001-3. Proposed Reliability Standard BAL-005-1, at Requirements
R1 and R8, would include the obligations currently under Requirement R3 of Reliability Standard
BAL-006-2.
1. Based on comments related to the SAR, the Independent Expert Review Report, and the
Periodic Review Team’ recommendations, the industry agrees that BAL-006 is an energy
accounting standard and not a Reliability Standard, however, it is unclear what the industry
supports as a replacement. The SDT has developed a white paper for the industry to
consider. Based on the concepts within the white paper, do you support maintaining Reliability
Standard BAL-006?[1]
0
Dislikes:
0
Dislikes:
0
0
Dislikes:
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
0
The current effective version of BAL-006 requires metering at all BAA
interconnection points (R3). The proposed version of BAL-006 removes the
requirement for metering. Although requirement for metering may be addressed
in changes to other BAL or FAC Standards, until that occurs BAL-006 should
remain as written.
Maintain BAL-006 (with no changes) as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
0
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Laurel Brandt - Tennessee Valley Authority - 1,3,5,6 - SERC
0
0
Dislikes:
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Jeri Freimuth - APS - Arizona Public Service Co. - 3 -
ISONE
IESO
MISO
NYISO
PJM
SPP
Kathleen Goodman
Ben Li
Terry Bilke
Greg Campoli
Mark Holman
Charles Yeung
2
Region(s)
Terry BIlke
Entity
2
2
2
2
2
2
2
Segments
0
0
Dislikes:
Our preference is to eliminate this standard with one caveat. We believe BAL006 should be converted to a guide and placed in the NERC Operating
Manual. The tasks done under this standard are useful housekeeping tasks that
support validation of balancing data.
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Midcontinent ISO, Inc.
Segment
SPP
RFC
NPCC
RFC
NPCC
Voter
Voter Information
TRE
ERCOT
Christina Bigelow
NPCC
Region
IRC-SRC
Group Member Name Entity
Group Name:
Group Information
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Southern Company
Alabama Power Company
Southern Company Generation
R Scott Moore
William Shultz
Region(s)
SERC
Entity
Southern Company - Southern Company
Services, Inc.
5
3
6
1
Segments
0
0
Dislikes:
Southern agrees with the PRT that BAL-006 is an energy accounting standard
and not a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Eliminate BAL-006 as a Reliability Standard.
1,3,5,6
Marsha Morgan
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
Southern Company Generation
and Energy Marketing
John Ciza
SERC
Southern Company Services, Inc SERC
Region
Robert Schaffeld
Group Member Name Entity
Group Name:
Group Information
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Duke Energy
Duke Energy
Duke Energy
Lee Schuster
Dale Goodwine
Greg Cecil
Region(s)
FRCC,SERC,RFC
Entity
Duke Energy
6
5
3
1
Segments
0
0
Dislikes:
Duke Energy supports the elimination of BAL-006 as a Reliability Standard,
based on the belief that the requirements, with the exception of certain
provisions of R4 incorporated into the proposed BAL-005-1, are business in
nature and are not needed to support the reliable operation of the Bulk
Power System.
Likes:
Document Name:
Answer Comment:
Eliminate BAL-006 as a Reliability Standard.
1,3,5,6
Colby Bellville
Selected Answer:
Segment
RFC
SERC
Voter
Voter Information
RFC
Duke Energy
Doug Hils
FRCC
Region
Duke Energy
Group Member Name Entity
Group Name:
Group Information
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
0
0
Dislikes:
While PJM agrees it is important to maintain requirements to calculate and
account for Inadvertent Interchange, PJM suggest this be moved to a NAESB
standard.
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Mark Holman - PJM Interconnection, L.L.C. - 2 -
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC
Brenda Truhe
Dan Wilson
Linn Oelker
Region(s)
SERC
Entity
PPL - Louisville Gas and Electric Co.
0
0
Dislikes:
In order to maintain enforcement capability, BAL-006 should remain a Reliability
Standard.
Likes:
Document Name:
Answer Comment:
6
5
1
3
Segments
Modify and maintain BAL-006 as a Reliability Standard.
1,3,5,6
Wayne Van Liere
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
SERC
LG&E and KU Energy, LLC
Charlie Freibert
RFC
Region
PPL NERC Registered Affiliates
Group Member Name Entity
Group Name:
Group Information
Wayne Van Liere - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC
FirstEnergy Corp.
Ohio Edison
FirstEnergy Solutions
FirstenergyCorp
FirstEnergy Solutions
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Region(s)
RFC
Entity
FirstEnergy - FirstEnergy Corporation
6
NA - Not
Applicable
5
4
3
1
Segments
0
0
Dislikes:
While PJM agrees it is important to maintain requirements to calculate and
account for Inadvertent Interchange, PJM suggest this be moved to a NAESB
standard.
FE supports PJM comments on this issue.
Likes:
Document Name:
Answer Comment:
Eliminate BAL-006 as a Reliability Standard.
1,3,4,5,6
Richard Hoag
Selected Answer:
Segment
FRCC
RFC
RFC
RFC
Voter
Voter Information
RFC
FirstenergyCorp
William Smith
RFC
Region
FE RBB
Group Member Name Entity
Group Name:
Group Information
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
0
Dislikes:
Santee Cooper
Santee Cooper
James Poston
Michael Brown
Region(s)
Entity
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Eliminate BAL-006 as a Reliability Standard.
1
Shawn Abrams
Santee Cooper
Segment
SERC
Voter
Voter Information
SERC
Santee Cooper
Shawn Abrams
SERC
Region
Santee Cooper
Group Member Name Entity
Group Name:
Group Information
Shawn Abrams - Santee Cooper - 1 -
0
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
6
3
1
Segments
0
Dislikes:
0
0
Dislikes:
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Don Schmit - Nebraska Public Power District - 5 -
0
Eliminate BAL-006 as a Reliability Standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Adam Padgett - TECO - Tampa Electric Co. - 1,3,5,6 - FRCC
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Ginger Mercier
Ellen Watkins
Michael Brytowski
Region(s)
NA - Not Applicable
Entity
ACES Power Marketing
1,3,5,6
1
1,3
1
Segments
0
0
Dislikes:
We believe the SDT has provided adequate analysis on supporting rationale to
eliminate BAL-006. Inadvertent Interchange is addressed through other existing
reliability and commercial requirements. However, we believe the SDT could
have provided better documentation to support its conclusions by identifying how
each requirement are addressed individually. We believe the SDT should
develop a “mapping document” that accompanies its white paper to better
substantiate its conclusions.
Likes:
Document Name:
Answer Comment:
Eliminate BAL-006 as a Reliability Standard.
6
Brian Van Gheem
Selected Answer:
Segment
MRO
SPP
Voter
Voter Information
RFC
Hoosier Energy Rural Electric
Cooperative, Inc.
Bob Solomon
SERC
Region
ACES Standards Collaborators
Group Member Name Entity
Group Name:
Group Information
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
2. If you support maintaining BAL-006 as a Reliability Standard, are you in favor of the PRT
recommendation as noted in the attached draft Reliability Standard BAL-006? If not, then what
aspects of BAL-006 should be retained in a standard?
0
Dislikes:
0
0
Dislikes:
See also answer to question 1.
The elimination of the currently effective BAL-006 R4 in the draft removes a
requirement that no other standard addresses.
Comments: The purpose listed in the draft of BAL-006 has not been changed
from the previously approved standard and does not appear directly related to the
drafted requirements.
No
Likes:
Document Name:
Answer Comment:
Selected Answer:
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Laurel Brandt - Tennessee Valley Authority - 1,3,5,6 - SERC
0
Dislikes:
0
0
Dislikes:
NA as AZPS does not support retaining as a NERC standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Jeri Freimuth - APS - Arizona Public Service Co. - 3 -
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
ISONE
IESO
MISO
NYISO
PJM
SPP
Kathleen Goodman
Ben Li
Terry Bilke
Greg Campoli
Mark Holman
Charles Yeung
2
Region(s)
Terry BIlke
Entity
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Midcontinent ISO, Inc.
Segment
SPP
RFC
NPCC
RFC
NPCC
Voter
Voter Information
TRE
ERCOT
Christina Bigelow
NPCC
Region
IRC-SRC
Group Member Name Entity
Group Name:
Group Information
Terry BIlke - Midcontinent ISO, Inc. - 2 -
2
2
2
2
2
2
2
Segments
Southern Company
Alabama Power Company
Southern Company Generation
R Scott Moore
William Shultz
Region(s)
SERC
Entity
Southern Company - Southern Company
Services, Inc.
0
0
Dislikes:
We suggest BAL-006 be retired.
Likes:
Document Name:
Answer Comment:
No
1,3,5,6
Marsha Morgan
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
Southern Company Generation
and Energy Marketing
John Ciza
SERC
Southern Company Services, Inc SERC
Region
Robert Schaffeld
Group Member Name Entity
Group Name:
Group Information
5
3
6
1
Segments
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Duke Energy
Duke Energy
Duke Energy
Lee Schuster
Dale Goodwine
Greg Cecil
1,3,5,6
Region(s)
FRCC,SERC,RFC
Colby Bellville
Entity
Duke Energy
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Segment
RFC
SERC
Voter
Voter Information
RFC
Duke Energy
Doug Hils
FRCC
Region
Duke Energy
Group Member Name Entity
Group Name:
Group Information
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
6
5
3
1
Segments
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Mark Holman - PJM Interconnection, L.L.C. - 2 -
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC
Brenda Truhe
Dan Wilson
Linn Oelker
Region(s)
SERC
Entity
PPL - Louisville Gas and Electric Co.
6
5
1
3
Segments
0
0
Dislikes:
To address FERC's recommendation for a metric to bind the magnitude of a BA's
inadvertent accumulation, LG&E and KU suggest a multiplier of L10. For
example, for a BA with an L10 of 100, a multiplier of 250 would permit an
accumulation of up to 25,000 MWHs. The limit on the accumulation needs to
reflect the relative size of the BA.
Likes:
Document Name:
Answer Comment:
Yes
1,3,5,6
Wayne Van Liere
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
SERC
LG&E and KU Energy, LLC
Charlie Freibert
RFC
Region
PPL NERC Registered Affiliates
Group Member Name Entity
Group Name:
Group Information
Wayne Van Liere - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC
FirstEnergy Corp.
Ohio Edison
FirstEnergy Solutions
FirstenergyCorp
FirstEnergy Solutions
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Region(s)
RFC
Entity
FirstEnergy - FirstEnergy Corporation
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Yes
1,3,4,5,6
Richard Hoag
Selected Answer:
Segment
FRCC
RFC
RFC
RFC
Voter
Voter Information
RFC
FirstenergyCorp
William Smith
RFC
Region
FE RBB
Group Member Name Entity
Group Name:
Group Information
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
6
NA - Not
Applicable
5
4
3
1
Segments
0
0
Dislikes:
BPA supports eliminating NERC BAL-006-2 as a reliability standard based on the
NERC SDT (Standard Drafting Team) white paper provided for consideration. As
the white paper suggests, the current requirements in NERC BAL-006-2 of a
reliability nature should be addressed through the requirements of the proposed
BAL-005-1.
No
Likes:
Document Name:
Answer Comment:
Selected Answer:
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Santee Cooper
Michael Brown
1
Region(s)
Shawn Abrams
Entity
0
Dislikes:
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Adam Padgett - TECO - Tampa Electric Co. - 1,3,5,6 - FRCC
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Santee Cooper
Segment
SERC
Voter
Yes
Santee Cooper
James Poston
Voter Information
SERC
Santee Cooper
Shawn Abrams
SERC
Region
Santee Cooper
Group Member Name Entity
Group Name:
Group Information
Shawn Abrams - Santee Cooper - 1 -
6
3
1
Segments
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Don Schmit - Nebraska Public Power District - 5 -
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Ginger Mercier
Ellen Watkins
Michael Brytowski
Region(s)
NA - Not Applicable
Entity
ACES Power Marketing
Likes:
Document Name:
Answer Comment:
1,3,5,6
1
1,3
1
Segments
0
We believe the SDT has provided adequate analysis on supporting reasons why
BAL-006 should be eliminated. We also believe that Paragraph 81 criteria could
be applied to eliminate the remaining requirements. Based on Paragraph 81
Criteria for Administrative and Reporting, we feel the SDT has provided sufficient
technical basis to substantiate that these requirements do “not support reliability
and is needlessly burdensome.” We also feel that in the instance when Adjacent
BAs do not agree upon interchange quantities, the need to report such disputes
to Regional Entities aligns with the definition of the Paragraph 81 Reporting
Criterion. This specific criterion states that “these are requirements that obligate
responsible entities to report to a Regional Entity on activities which have no
discernible impact on promoting the reliable operation of the BES and if the entity
failed to meet this requirement there would be little reliability impact.”
No
6
Brian Van Gheem
Selected Answer:
Segment
MRO
SPP
Voter
Voter Information
RFC
Hoosier Energy Rural Electric
Cooperative, Inc.
Bob Solomon
SERC
Region
ACES Standards Collaborators
Group Member Name Entity
Group Name:
Group Information
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
Dislikes:
0
3. If you support eliminating BAL-006 as a Reliability Standard, are you in favor of the SDT
recommendation that these requirements be included in a commercial alternative arrangement,
such as a NAESB standard or a process established by FERC? What aspects of BAL-006 should
be retained in an alternative arrangement?
0
Dislikes:
0
Dislikes:
0
0
Dislikes:
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
0
See answers to question 1 and 2 for elements of the current BAL-006 that would
need to be addressed in reliability standards.
NERC could accomplish the data collection under rules of procedure as opposed
to a reliability standard.
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
0
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Laurel Brandt - Tennessee Valley Authority - 1,3,5,6 - SERC
0
0
Dislikes:
Reconciliation of inadvertent
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Jeri Freimuth - APS - Arizona Public Service Co. - 3 -
ISONE
IESO
MISO
NYISO
PJM
SPP
Kathleen Goodman
Ben Li
Terry Bilke
Greg Campoli
Mark Holman
Charles Yeung
2
Region(s)
Terry BIlke
Entity
Likes:
Document Name:
Answer Comment:
Selected Answer:
2
2
2
2
2
2
2
Segments
0
The guidelines or procedure could be drafted and maintained in the operating
manual by taking the existing verbiage and replace “shall” with “will”, “needs to”,
or “should”.
We do not support turning this over to NAESB or FERC. NAESB business
practices ultimately become part of a transmission provider’s tariff. Not all
transmission providers are Balancing Authorities. Additionally, not all Balancing
Authorities are FERC jurisdictional. Rather than creating gaps and make the data
unverifiable, our preference is that BAL-006 be converted to a guide or procedure
and placed in the NERC Operating Manual.
No
Midcontinent ISO, Inc.
Segment
SPP
RFC
NPCC
RFC
NPCC
Voter
Voter Information
TRE
ERCOT
Christina Bigelow
NPCC
Region
IRC-SRC
Group Member Name Entity
Group Name:
Group Information
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Dislikes:
0
Southern Company
Alabama Power Company
Southern Company Generation
R Scott Moore
William Shultz
Region(s)
SERC
Entity
Southern Company - Southern Company
Services, Inc.
5
3
6
1
Segments
0
0
Dislikes:
Southern would prefer this be handled with agreements between the
entities. However, if a standard is required, we suggest it be within NAESB and
not a NERC Reliability Standard.
Likes:
Document Name:
Answer Comment:
No
1,3,5,6
Marsha Morgan
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
Southern Company Generation
and Energy Marketing
John Ciza
SERC
Southern Company Services, Inc SERC
Region
Robert Schaffeld
Group Member Name Entity
Group Name:
Group Information
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Duke Energy
Duke Energy
Dale Goodwine
Greg Cecil
Region(s)
FRCC,SERC,RFC
Entity
Duke Energy
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
6
5
3
1
Segments
Duke Energy recommends moving the responsibilities present in R1-R3, as
well as R4.1 of BAL-006 to the NAESB standards. NAESB already handles
certain aspects of Interchange, and Inadvertent accounting is considered to
be a business practice or commercial in nature. We believe the
requirements listed above fit that description. We have excluded R4 from
moving to NAESB, as we believe it would be covered by the proposed BAL005-1 upon approval.
1,3,5,6
Colby Bellville
Selected Answer:
Segment
RFC
SERC
Voter
Yes
Duke Energy
Lee Schuster
Voter Information
RFC
Duke Energy
Doug Hils
FRCC
Region
Duke Energy
Group Member Name Entity
Group Name:
Group Information
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
0
0
Dislikes:
PJM believes the requirements in BAL-006 should be moved to a NAESB
standard. In order for Inadvertent Interchange to be calculated appropriately the
standard should include requirements similar to what the PRT has suggested for
BAL-006. However PJM also believes that Adjacent Balancing Authorities should
operate to a Net Interchange Schedule as this is important to avoid many
potential dispute resolutions.
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Mark Holman - PJM Interconnection, L.L.C. - 2 -
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC
Brenda Truhe
Dan Wilson
Linn Oelker
1,3,5,6
Region(s)
SERC
Wayne Van Liere
Entity
PPL - Louisville Gas and Electric Co.
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
SERC
LG&E and KU Energy, LLC
Charlie Freibert
RFC
Region
PPL NERC Registered Affiliates
Group Member Name Entity
Group Name:
Group Information
Wayne Van Liere - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC
6
5
1
3
Segments
FirstEnergy Corp.
Ohio Edison
FirstEnergy Solutions
FirstenergyCorp
FirstEnergy Solutions
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Region(s)
RFC
Entity
FirstEnergy - FirstEnergy Corporation
6
NA - Not
Applicable
5
4
3
1
Segments
0
0
Dislikes:
PJM believes the requirements in BAL-006 should be moved to a NAESB
standard. In order for Inadvertent Interchange to be calculated appropriately the
standard should include requirements similar to what the PRT has suggested for
BAL-006. However PJM also believes that Adjacent Balancing Authorities should
operate to a Net Interchange Schedule as this is important to avoid many
potential dispute resolutions.
FE supports PJM comments on this issue.
Likes:
Document Name:
Answer Comment:
Yes
1,3,4,5,6
Richard Hoag
Selected Answer:
Segment
FRCC
RFC
RFC
RFC
Voter
Voter Information
RFC
FirstenergyCorp
William Smith
RFC
Region
FE RBB
Group Member Name Entity
Group Name:
Group Information
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
0
Dislikes:
Santee Cooper
Michael Brown
Region(s)
Entity
Likes:
Document Name:
Answer Comment:
Selected Answer:
6
3
1
Segments
0
We support maintaining the current reporting requirements through the CERTS
Inadvertent Interchange Reporting Application.
1
Shawn Abrams
Santee Cooper
Segment
SERC
Voter
Yes
Santee Cooper
James Poston
Voter Information
SERC
Santee Cooper
Shawn Abrams
SERC
Region
Santee Cooper
Group Member Name Entity
Group Name:
Group Information
Shawn Abrams - Santee Cooper - 1 -
0
No
Likes:
Document Name:
Answer Comment:
Selected Answer:
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
0
Refer it to NAESB and incorporate all of the BAL-006 requirements in a NAESB
standard.
Yes
Adam Padgett - TECO - Tampa Electric Co. - 1,3,5,6 - FRCC
Dislikes:
0
0
0
Dislikes:
Yes
Likes:
Document Name:
Answer Comment:
Selected Answer:
Don Schmit - Nebraska Public Power District - 5 -
Dislikes:
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Ginger Mercier
Ellen Watkins
Michael Brytowski
Region(s)
NA - Not Applicable
Entity
ACES Power Marketing
1,3,5,6
1
1,3
1
Segments
0
0
Dislikes:
We agree that commercial alternative arrangements, such as a NAESB Business
Practices, are a better fit for Inadvertent Interchange.
Likes:
Document Name:
Answer Comment:
Yes
6
Brian Van Gheem
Selected Answer:
Segment
MRO
SPP
Voter
Voter Information
RFC
Hoosier Energy Rural Electric
Cooperative, Inc.
Bob Solomon
SERC
Region
ACES Standards Collaborators
Group Member Name Entity
Group Name:
Group Information
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
4. If neither maintaining nor eliminating BAL-006 is preferred, please describe your suggestion
for the disposition of this standard.
0
Dislikes:
0
Dislikes:
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Laurel Brandt - Tennessee Valley Authority - 1,3,5,6 - SERC
0
0
Dislikes:
Support transferring to NAESB
Likes:
Document Name:
Answer Comment:
Selected Answer:
Jeri Freimuth - APS - Arizona Public Service Co. - 3 -
ISONE
IESO
MISO
NYISO
PJM
SPP
Kathleen Goodman
Ben Li
Terry Bilke
Greg Campoli
Mark Holman
Charles Yeung
2
Region(s)
Terry BIlke
Entity
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Midcontinent ISO, Inc.
Segment
SPP
RFC
NPCC
RFC
NPCC
Voter
Voter Information
TRE
ERCOT
Christina Bigelow
NPCC
Region
IRC-SRC
Group Member Name Entity
Group Name:
Group Information
Terry BIlke - Midcontinent ISO, Inc. - 2 -
2
2
2
2
2
2
2
Segments
Southern Company
Alabama Power Company
Southern Company Generation
R Scott Moore
William Shultz
Region(s)
SERC
Entity
Southern Company - Southern Company
Services, Inc.
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
NA
1,3,5,6
Marsha Morgan
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
Southern Company Generation
and Energy Marketing
John Ciza
SERC
Southern Company Services, Inc SERC
Region
Robert Schaffeld
Group Member Name Entity
Group Name:
Group Information
5
3
6
1
Segments
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Duke Energy
Duke Energy
Duke Energy
Lee Schuster
Dale Goodwine
Greg Cecil
1,3,5,6
Region(s)
FRCC,SERC,RFC
Colby Bellville
Entity
Duke Energy
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Segment
RFC
SERC
Voter
Voter Information
RFC
Duke Energy
Doug Hils
FRCC
Region
Duke Energy
Group Member Name Entity
Group Name:
Group Information
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
6
5
3
1
Segments
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Mark Holman - PJM Interconnection, L.L.C. - 2 -
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC
Brenda Truhe
Dan Wilson
Linn Oelker
1,3,5,6
Region(s)
SERC
Wayne Van Liere
Entity
PPL - Louisville Gas and Electric Co.
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
SERC
LG&E and KU Energy, LLC
Charlie Freibert
RFC
Region
PPL NERC Registered Affiliates
Group Member Name Entity
Group Name:
Group Information
Wayne Van Liere - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC
6
5
1
3
Segments
FirstEnergy Corp.
Ohio Edison
FirstEnergy Solutions
FirstenergyCorp
FirstEnergy Solutions
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Region(s)
RFC
Entity
FirstEnergy - FirstEnergy Corporation
6
NA - Not
Applicable
5
4
3
1
Segments
0
0
Dislikes:
This question is not applicable as PJM feels that Inadvertent Interchange
requirements should be moved to a NAESB standard.
Likes:
Document Name:
Answer Comment:
FE supports PJM comments on this issue.
1,3,4,5,6
Richard Hoag
Selected Answer:
Segment
FRCC
RFC
RFC
RFC
Voter
Voter Information
RFC
FirstenergyCorp
William Smith
RFC
Region
FE RBB
Group Member Name Entity
Group Name:
Group Information
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
0
Dislikes:
Santee Cooper
Michael Brown
1
Region(s)
Shawn Abrams
Entity
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Santee Cooper
Segment
SERC
Voter
n/a
Santee Cooper
James Poston
Voter Information
SERC
Santee Cooper
Shawn Abrams
SERC
Region
Santee Cooper
Group Member Name Entity
Group Name:
Group Information
Shawn Abrams - Santee Cooper - 1 -
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
6
3
1
Segments
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Adam Padgett - TECO - Tampa Electric Co. - 1,3,5,6 - FRCC
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Don Schmit - Nebraska Public Power District - 5 -
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Ginger Mercier
Ellen Watkins
Michael Brytowski
Region(s)
NA - Not Applicable
Entity
ACES Power Marketing
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
We suggest that the SDT eliminate BAL-006.
6
Brian Van Gheem
Selected Answer:
Segment
MRO
SPP
Voter
Voter Information
RFC
Hoosier Energy Rural Electric
Cooperative, Inc.
Bob Solomon
SERC
Region
ACES Standards Collaborators
Group Member Name Entity
Group Name:
Group Information
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
1,3,5,6
1
1,3
1
Segments
5. If you have any other comments or reliability concerns, please provide them in the space
below.
0
Dislikes:
0
Dislikes:
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
0
Requirements in BAL-006 as proposed for deletion are of value in a Standard,
see answers to Question 1 and 2.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RFC
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Laurel Brandt - Tennessee Valley Authority - 1,3,5,6 - SERC
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Jeri Freimuth - APS - Arizona Public Service Co. - 3 -
ISONE
IESO
MISO
NYISO
PJM
SPP
Kathleen Goodman
Ben Li
Terry Bilke
Greg Campoli
Mark Holman
Charles Yeung
2
Region(s)
Terry BIlke
Entity
2
2
2
2
2
2
2
Segments
0
0
Dislikes:
If our suggestion is not supported, we would suggest balloting the posted
standard and make the VRFs and VSLs reflect the fact that the requirements in
this standard have little or no impact on reliability.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Midcontinent ISO, Inc.
Segment
SPP
RFC
NPCC
RFC
NPCC
Voter
Voter Information
TRE
ERCOT
Christina Bigelow
NPCC
Region
IRC-SRC
Group Member Name Entity
Group Name:
Group Information
Terry BIlke - Midcontinent ISO, Inc. - 2 -
Southern Company
Alabama Power Company
Southern Company Generation
R Scott Moore
William Shultz
Region(s)
SERC
Entity
Southern Company - Southern Company
Services, Inc.
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
NA
1,3,5,6
Marsha Morgan
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
Southern Company Generation
and Energy Marketing
John Ciza
SERC
Southern Company Services, Inc SERC
Region
Robert Schaffeld
Group Member Name Entity
Group Name:
Group Information
5
3
6
1
Segments
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Duke Energy
Duke Energy
Duke Energy
Lee Schuster
Dale Goodwine
Greg Cecil
Region(s)
FRCC,SERC,RFC
Entity
Duke Energy
0
0
Dislikes:
Given that the proposed BAL-005-1 will include a requirement covering the
current BAL-006 R4, Duke Energy recommends that the BAL-005-1
implementation plan factor in the possible hand over of BAL-006
responsibilities from NERC to NAESB so that there isn’t the possibility of
BAL-005-1 being effective at the same time that BAL-006 is still in place with
a duplicate requirement.
Likes:
Document Name:
Answer Comment:
6
5
3
1
Segments
Duke Energy’s support for the elimination of BAL-006 as a Reliability
Standard, and the aforementioned requirements transition to the NAESB
standards, predicated on the assumption that the Real-time reliability
requirements of BAL-006 will be covered in one way (approval of proposed
BAL-005-1) or another (incorporated into an existing BAL standard).
1,3,5,6
Colby Bellville
Selected Answer:
Segment
RFC
SERC
Voter
Voter Information
RFC
Duke Energy
Doug Hils
FRCC
Region
Duke Energy
Group Member Name Entity
Group Name:
Group Information
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC
0
0
Dislikes:
As part of Project 2010-14.2.1 Phase 2 it was suggested that BAL-006-2
Requirement R3 be moved into BAL-005-3. While PJM agrees it is important to
calculate MWh values for Inadvertent Interchange, PJM suggests this be moved
to a NAESB standard.
Likes:
Document Name:
Answer Comment:
Selected Answer:
Mark Holman - PJM Interconnection, L.L.C. - 2 -
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC
Brenda Truhe
Dan Wilson
Linn Oelker
Region(s)
SERC
Entity
PPL - Louisville Gas and Electric Co.
0
0
Dislikes:
LG&E and KU are not in favor of financial or FERC established processes for
settlement of accumulated inadvertent accounts.
Likes:
Document Name:
Answer Comment:
6
5
1
3
Segments
LG&E and KU are not opposed to handling inadvertent via a NAESB standard or
business practice; the concern is enforceability. A NAESB standard or business
practice for inadvertent would lack enforcement "teeth." Thus LG&E and KU
question whether a NAESB standard can as effectivelty achieve the desired
result.
1,3,5,6
Wayne Van Liere
Selected Answer:
Segment
SERC
SERC
Voter
Voter Information
SERC
LG&E and KU Energy, LLC
Charlie Freibert
RFC
Region
PPL NERC Registered Affiliates
Group Member Name Entity
Group Name:
Group Information
Wayne Van Liere - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC
FirstEnergy Corp.
Ohio Edison
FirstEnergy Solutions
FirstenergyCorp
FirstEnergy Solutions
Cindy Stewart
Doug Hohlbaugh
Robert Loy
Richard Hoag
Ann Ivanc
Region(s)
RFC
Entity
FirstEnergy - FirstEnergy Corporation
6
NA - Not
Applicable
5
4
3
1
Segments
0
0
Dislikes:
As part of Project 2010-14.2.1 Phase 2 it was suggested that BAL-006-2
Requirement R3 be moved into BAL-005-3. While PJM agrees it is important to
calculate MWh values for Inadvertent Interchange, PJM suggests this be moved
to a NAESB standard.
Likes:
Document Name:
Answer Comment:
FE supports PJM comments on this issue.
1,3,4,5,6
Richard Hoag
Selected Answer:
Segment
FRCC
RFC
RFC
RFC
Voter
Voter Information
RFC
FirstenergyCorp
William Smith
RFC
Region
FE RBB
Group Member Name Entity
Group Name:
Group Information
Richard Hoag - FirstEnergy - FirstEnergy Corporation - 1,3,4,5,6 - RFC
0
Dislikes:
Santee Cooper
Michael Brown
1
Region(s)
Shawn Abrams
Entity
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Santee Cooper
Segment
SERC
Voter
n/a
Santee Cooper
James Poston
Voter Information
SERC
Santee Cooper
Shawn Abrams
SERC
Region
Santee Cooper
Group Member Name Entity
Group Name:
Group Information
Shawn Abrams - Santee Cooper - 1 -
0
Likes:
Document Name:
Answer Comment:
Selected Answer:
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
6
3
1
Segments
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Adam Padgett - TECO - Tampa Electric Co. - 1,3,5,6 - FRCC
0
0
Likes:
Dislikes:
Document Name:
Answer Comment:
Selected Answer:
Don Schmit - Nebraska Public Power District - 5 -
Prairie Power, Inc.
Sunflower Electric Power
Corporation
Great River Energy
Ginger Mercier
Ellen Watkins
Michael Brytowski
Region(s)
NA - Not Applicable
Entity
ACES Power Marketing
0
0
Dislikes:
Thank you for the opportunity to comment.
Likes:
Document Name:
Answer Comment:
1,3,5,6
1
1,3
1
Segments
We question the practice of NERC posting this survey with the expectation of a
nine-day, weekend included, turnaround for the possible elimination of a reliability
standard. This survey was posted during a week with NERC Technical
Committee meetings, which likely impacted the availability of many industry and
NERC subject matter experts to provide comments. We hope this condensed
commenting period was an oversight and a one-time occurrence.
6
Brian Van Gheem
Selected Answer:
Segment
MRO
SPP
Voter
Voter Information
RFC
Hoosier Energy Rural Electric
Cooperative, Inc.
Bob Solomon
SERC
Region
ACES Standards Collaborators
Group Member Name Entity
Group Name:
Group Information
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable
CommentPeriodEndDate:9/25/2015
CommentPeriodStartDate:9/16/2015
ProjectName:2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControls|BALͲ006Survey
Consideration of Comments
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
1
TheNERCStandardsCommitteeappointedelevenindustrysubjectmatterexpertstoserveontheBARC2periodicreviewteam
(BARC2PRT)inthefallof2013.TheBARC2PRTusedbackgroundinformationonthestandardsandthequestionssetforthinthe
PeriodicReviewTemplatedevelopedbyNERCandapprovedbytheStandardsCommittee,alongwithassociatedworksheetsand
referencedocuments,todeterminewhetherBALͲ006Ͳ2shouldbe:(1)affirmedasis(i.e.,nochangesneeded);(2)revised(which
mayincluderevisingorretiringoneormorerequirements);or(3)withdrawn.Duringthedevelopmentoftherecommendation,the
PRTalsoconsideredstakeholderrecommendationsforcandidateParagraph81requirementsfromPhase1ofParagraph81,and
appliedtheParagraph81criteriatoalloftherequirements.TheteamalsoconsideredtheIndependentExpertReviewPanel
recommendationsonthestandard.
Therewere14responses,includingcommentsfromapproximately43differentpeoplefromapproximately33differentcompanies
representing6ofthe10IndustrySegmentsasshownonthefollowingpages.
Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogiveeverycommentserious
considerationinthisprocess.Ifyoufeeltherehasbeenanerrororomission,youcancontacttheDirectorofStandards,Howard
Gugel(viaemail)orat(404)446Ͳ9693.
SummaryResponse
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
2
TheBARC2.1SDT’srecommendationforretirementofBALͲ006Ͳ0iscontingentonsimultaneousestablishmentofaNERCOperating
CommitteeGuidelinefortheongoingrequiredaccountingofinadvertentinterchange.TheBARC2.1SDTiscoordinatingthe
developmentofsuchaguidelinewiththeNERCOperatingCommittee.
TheBalancingAuthorityReliabilityͲbasedControls2.1StandardDraftingTeam(BARC2.1SDT)reviewedthefindingsoftheBARC2
PrimaryReviewTeam.AsurveywaspostedforcommentSeptember16Ͳ25,2015togainabetterperspectiveastoanyconcernsthe
industrymayhaveifBALͲ006Ͳ2wasretiredandreplacedwithanonͲreliabilityprocess,suchasaguidelineorabusinesspractice.
ThesurveyresponsesindicatedsupportforretirementofBALͲ006Ͳ2asaNERCReliabilityStandard.UponfurtherreviewtheBARC
2.1SDTdeterminedthatBALͲ006Ͳ2doesnotsupportthereliabilityoftheBES.BALͲ006Ͳ2isanaccountingbusinessrequirementand
notareliabilitystandard.ThereforeBALͲ006Ͳ2shouldberetired.
Afteranextensivereview,theBARC2PRTconcludedthatReliabilityStandardBALͲ006Ͳ2wasnotareliabilitystandard,however,
certainprovisionwerenecessaryfortheoperationsoftheInterconnection.
5. Ifyouhaveanyothercommentsorreliabilityconcerns,pleaseprovidetheminthespacebelow.
1—TransmissionOwners
2—RTOs,ISOs
3—LoadͲservingEntities
4—TransmissionͲdependentUtilities
5—ElectricGenerators
6—ElectricityBrokers,Aggregators,andMarketers
7—LargeElectricityEndUsers
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
3
Whenrespondingtothissurveyandprovidingcomments,pleasekeepinmindthatdraftproposedReliabilityStandardBALͲ006Ͳ3hasbeenpostedunder2010Ͳ14.2.1
Phase2ofBalancingAuthorityReliabilityͲbasedControls,inconnectionwithdraftproposedReliabilityStandardsBALͲ005Ͳ1andFACͲ001Ͳ3.ProposedReliabilityStandardBALͲ
005Ͳ1,atRequirementsR1andR8,wouldincludetheobligationscurrentlyunderRequirementR3ofReliabilityStandardBALͲ006Ͳ2.
1
The Industry Segments are:
4. IfneithermaintainingnoreliminatingBALͲ006ispreferred,pleasedescribeyoursuggestionforthedispositionofthis
standard.
3. IfyousupporteliminatingBALͲ006asaReliabilityStandard,areyouinfavoroftheSDTrecommendationthatthese
requirementsbeincludedinacommercialalternativearrangement,suchasaNAESBstandardoraprocessestablishedby
FERC?WhataspectsofBALͲ006shouldberetainedinanalternativearrangement?
2. IfyousupportmaintainingBALͲ006asaReliabilityStandard,areyouinfavorofthePRTrecommendationasnotedinthe
attacheddraftReliabilityStandardBALͲ006?Ifnot,thenwhataspectsofBALͲ006shouldberetainedinastandard?
1. BasedoncommentsrelatedtotheSAR,theIndependentExpertReviewReport,andthePeriodicReviewTeam’
recommendations,theindustryagreesthatBALͲ006isanenergyaccountingstandardandnotaReliabilityStandard,
however,itisunclearwhattheindustrysupportsasareplacement.TheSDThasdevelopedawhitepaperfortheindustry
toconsider.Basedontheconceptswithinthewhitepaper,doyousupportmaintainingReliabilityStandardBALͲ006?1
Questions
8—SmallElectricityEndUsers
9—Federal,State,ProvincialRegulatoryorotherGovernmentEntities
10—RegionalReliabilityOrganizations,RegionalEntities
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
4
5
1.BasedoncommentsrelatedtotheSAR,theIndependentExpertReviewReport,andthePeriodicReviewTeam’
recommendations,theindustryagreesthatBALͲ006isanenergyaccountingstandardandnotaReliabilityStandard,however,
itisunclearwhattheindustrysupportsasareplacement.TheSDThasdevelopedawhitepaperfortheindustryto
consider.Basedontheconceptswithinthewhitepaper,doyousupportmaintainingReliabilityStandardBALͲ006?[1]
[1]Whenrespondingtothissurveyandprovidingcomments,pleasekeepinmindthatdraftproposedReliability
StandardBALͲ006Ͳ3hasbeenpostedunder2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControls,inconnection
withdraftproposedReliabilityStandardsBALͲ005Ͳ1andFACͲ001Ͳ3.ProposedReliabilityStandardBALͲ005Ͳ1,atRequirements
R1andR8,wouldincludetheobligationscurrentlyunderRequirementR3ofReliabilityStandardBALͲ006Ͳ2.
LaurelBrandtͲTennesseeValleyAuthorityͲ1,3,5,6ͲSERC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
MaintainBALͲ006(withnochanges)asaReliabilityStandard.
AnswerComment:
ThecurrenteffectiveversionofBALͲ006requiresmeteringatallBAA
interconnectionpoints(R3).TheproposedversionofBALͲ006removes
therequirementformetering.Althoughrequirementformeteringmay
beaddressedinchangestootherBALorFACStandards,untilthatoccurs
BALͲ006shouldremainaswritten.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
Ourpreferenceistoeliminatethisstandardwithonecaveat.Webelieve
BALͲ006shouldbeconvertedtoaguideandplacedintheNERC
OperatingManual.Thetasksdoneunderthisstandardareuseful
housekeepingtasksthatsupportvalidationofbalancingdata.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
6
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
SouthernagreeswiththePRTthatBALͲ006isanenergyaccounting
standardandnotaReliabilityStandard.
Response:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
7
DougHils
LeeSchuster
DaleGoodwine
GregCecil
SelectedAnswer:
AnswerComment:
Regio Segmen
n
ts
DukeEnergy
RFC
1
DukeEnergy
FRCC 3
DukeEnergy
SERC 5
DukeEnergy
RFC
6
EliminateBALͲ006asaReliabilityStandard.
DukeEnergysupportstheeliminationofBALͲ006asaReliability
Standard,basedonthebeliefthattherequirements,withthe
exceptionofcertainprovisionsofR4incorporatedintotheproposed
BALͲ005Ͳ1,arebusinessinnatureandarenotneededtosupportthe
reliableoperationoftheBulkPowerSystem.
Entity
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
WhilePJMagreesitisimportanttomaintainrequirementstocalculate
andaccountforInadvertentInterchange,PJMsuggestthisbemovedtoa
NAESBstandard.
Response:
GroupMemberName
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
8
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
Regio Segmen
n
ts
CharlieFreibert
LG&EandKUEnergy,LLC
SERC 3
BrendaTruhe
PPLElectricUtilitiesCorporation
RFC
1
DanWilson
LG&EandKUEnergy,LLC
SERC 5
LinnOelker
LG&EandKUEnergy,LLC
SERC 6
SelectedAnswer:
ModifyandmaintainBALͲ006asaReliabilityStandard.
AnswerComment:
Inordertomaintainenforcementcapability,BALͲ006shouldremaina
ReliabilityStandard.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
9
FirstenergyCorp
RFC
10
NAͲNot
Applicab
le
6
AnnIvanc
FirstEnergySolutions
FRCC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
FEsupportsPJMcommentsonthisissue.
WhilePJMagreesitisimportanttomaintainrequirementstocalculate
andaccountforInadvertentInterchange,PJMsuggestthisbemovedtoa
NAESBstandard.
Response:
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
RichardHoag
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AdamPadgettͲTECOͲTampaElectricCo.Ͳ1,3,5,6ͲFRCC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
DonSchmitͲNebraskaPublicPowerDistrictͲ5Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
WebelievetheSDThasprovidedadequateanalysisonsupporting
rationaletoeliminateBALͲ006.InadvertentInterchangeisaddressed
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
11
12
throughotherexistingreliabilityandcommercial
requirements.However,webelievetheSDTcouldhaveprovidedbetter
documentationtosupportitsconclusionsbyidentifyinghoweach
requirementareaddressedindividually.WebelievetheSDTshould
developa“mappingdocument”thataccompaniesitswhitepaperto
bettersubstantiateitsconclusions.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
2.IfyousupportmaintainingBALͲ006asaReliabilityStandard,areyouinfavorofthePRTrecommendationasnotedin
theattacheddraftReliabilityStandardBALͲ006?Ifnot,thenwhataspectsofBALͲ006shouldberetainedinastandard?
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
No
AnswerComment:
Comments:ThepurposelistedinthedraftofBALͲ006hasnotbeen
changedfromthepreviouslyapprovedstandardanddoesnotappear
directlyrelatedtothedraftedrequirements.
TheeliminationofthecurrentlyeffectiveBALͲ006R4inthedraftremoves
arequirementthatnootherstandardaddresses.
Seealsoanswertoquestion1.
Response:
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
AnswerComment:
NAasAZPSdoesnotsupportretainingasaNERCstandard.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
13
GroupName:
SouthernCompany
GroupMemberName
Entity
RobertSchaffeld
SouthernCompanyServices,Inc
JohnCiza
SouthernCompanyGeneration
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
WilliamShultz
SouthernCompanyGeneration
SelectedAnswer:
No
AnswerComment:
WesuggestBALͲ006beretired.
Response:
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
CharlieFreibert
LG&EandKUEnergy,LLC
BrendaTruhe
PPLElectricUtilitiesCorporation
DanWilson
LG&EandKUEnergy,LLC
LinnOelker
LG&EandKUEnergy,LLC
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
Segmen
ts
1
6
3
5
Regio
n
SERC
SERC
SERC
SERC
Segmen
ts
3
1
5
6
Regio
n
SERC
RFC
SERC
SERC
14
AnswerComment:
ToaddressFERC'srecommendationforametrictobindthemagnitudeof
aBA'sinadvertentaccumulation,LG&EandKUsuggestamultiplierof
L10.Forexample,foraBAwithanL10of100,amultiplierof250would
permitanaccumulationofupto25,000MWHs.Thelimitonthe
accumulationneedstoreflecttherelativesizeoftheBA.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
RichardHoag
FirstenergyCorp
RFC
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
SelectedAnswer:
Yes
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
15
SelectedAnswer:
No
AnswerComment:
BPAsupportseliminatingNERCBALͲ006Ͳ2asareliabilitystandardbased
ontheNERCSDT(StandardDraftingTeam)whitepaperprovidedfor
consideration.Asthewhitepapersuggests,thecurrentrequirementsin
NERCBALͲ006Ͳ2ofareliabilitynatureshouldbeaddressedthroughthe
requirementsoftheproposedBALͲ005Ͳ1.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
16
BobSolomon
17
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
PrairiePower,Inc.
SERC 1,3
SunflowerElectricPower
SPP
1
Corporation
GreatRiverEnergy
MRO 1,3,5,6
No
WebelievetheSDThasprovidedadequateanalysisonsupporting
reasonswhyBALͲ006shouldbeeliminated.Wealsobelievethat
Paragraph81criteriacouldbeappliedtoeliminatetheremaining
requirements.BasedonParagraph81CriteriaforAdministrativeand
Reporting,wefeeltheSDThasprovidedsufficienttechnicalbasisto
substantiatethattheserequirementsdo“notsupportreliabilityandis
needlesslyburdensome.”Wealsofeelthatintheinstancewhen
AdjacentBAsdonotagreeuponinterchangequantities,theneedto
reportsuchdisputestoRegionalEntitiesalignswiththedefinitionofthe
Paragraph81ReportingCriterion.Thisspecificcriterionstatesthat
“thesearerequirementsthatobligateresponsibleentitiestoreporttoa
RegionalEntityonactivitieswhichhavenodiscernibleimpacton
promotingthereliableoperationoftheBESandiftheentityfailedto
meetthisrequirementtherewouldbelittlereliabilityimpact.”
Response:
GingerMercier
EllenWatkins
MichaelBrytowski
SelectedAnswer:
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
3.IfyousupporteliminatingBALͲ006asaReliabilityStandard,areyouinfavoroftheSDTrecommendationthatthese
requirementsbeincludedinacommercialalternativearrangement,suchasaNAESBstandardoraprocessestablished
byFERC?WhataspectsofBALͲ006shouldberetainedinanalternativearrangement?
LaurelBrandtͲTennesseeValleyAuthorityͲ1,3,5,6ͲSERC
SelectedAnswer:
Yes
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
Yes
AnswerComment:
NERCcouldaccomplishthedatacollectionunderrulesofprocedureas
opposedtoareliabilitystandard.
Seeanswerstoquestion1and2forelementsofthecurrentBALͲ006that
wouldneedtobeaddressedinreliabilitystandards.
Response:
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
Yes
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
18
SelectedAnswer:
Yes
AnswerComment:
Reconciliationofinadvertent
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
SelectedAnswer:
No
AnswerComment:
WedonotsupportturningthisovertoNAESBorFERC.NAESBbusiness
practicesultimatelybecomepartofatransmissionprovider’stariff.Not
alltransmissionprovidersareBalancingAuthorities.Additionally,notall
BalancingAuthoritiesareFERCjurisdictional.Ratherthancreatinggaps
andmakethedataunverifiable,ourpreferenceisthatBALͲ006be
convertedtoaguideorprocedureandplacedintheNERCOperating
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
19
20
Manual.
Theguidelinesorprocedurecouldbedraftedandmaintainedinthe
operatingmanualbytakingtheexistingverbiageandreplace“shall”with
“will”,“needsto”,or“should”.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
SelectedAnswer:
No
AnswerComment:
Southernwouldpreferthisbehandledwithagreementsbetweenthe
entities.However,ifastandardisrequired,wesuggestitbewithin
NAESBandnotaNERCReliabilityStandard.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio Segmen
n
ts
DougHils
DukeEnergy
RFC
1
LeeSchuster
DukeEnergy
FRCC 3
DaleGoodwine
DukeEnergy
SERC 5
GregCecil
DukeEnergy
RFC
6
SelectedAnswer:
Yes
AnswerComment:
DukeEnergyrecommendsmovingtheresponsibilitiespresentinR1ͲR3,
aswellasR4.1ofBALͲ006totheNAESBstandards.NAESBalready
handlescertainaspectsofInterchange,andInadvertentaccountingis
consideredtobeabusinesspracticeorcommercialinnature.We
believetherequirementslistedabovefitthatdescription.Wehave
excludedR4frommovingtoNAESB,aswebelieveitwouldbecovered
bytheproposedBALͲ005Ͳ1uponapproval.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
21
22
PJMbelievestherequirementsinBALͲ006shouldbemovedtoaNAESB
standard.InorderforInadvertentInterchangetobecalculated
appropriatelythestandardshouldincluderequirementssimilartowhat
thePRThassuggestedforBALͲ006.HoweverPJMalsobelievesthat
AdjacentBalancingAuthoritiesshouldoperatetoaNetInterchange
Scheduleasthisisimportanttoavoidmanypotentialdisputeresolutions.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
RichardHoag
FirstenergyCorp
RFC
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
SelectedAnswer:
Yes
AnswerComment:
FEsupportsPJMcommentsonthisissue.
PJMbelievestherequirementsinBALͲ006shouldbemovedtoaNAESB
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
23
standard.InorderforInadvertentInterchangetobecalculated
appropriatelythestandardshouldincluderequirementssimilartowhat
thePRThassuggestedforBALͲ006.HoweverPJMalsobelievesthat
AdjacentBalancingAuthoritiesshouldoperatetoaNetInterchange
Scheduleasthisisimportanttoavoidmanypotentialdisputeresolutions.
Response:
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
No
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
SelectedAnswer:
Yes
AnswerComment:
Wesupportmaintainingthecurrentreportingrequirementsthroughthe
CERTSInadvertentInterchangeReportingApplication.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
AdamPadgettͲTECOͲTampaElectricCo.Ͳ1,3,5,6ͲFRCC
SelectedAnswer:
Yes
AnswerComment:
ReferittoNAESBandincorporatealloftheBALͲ006requirementsina
NAESBstandard.
Response:
DonSchmitͲNebraskaPublicPowerDistrictͲ5Ͳ
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
24
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
SelectedAnswer:
Yes
AnswerComment:
Weagreethatcommercialalternativearrangements,suchasaNAESB
BusinessPractices,areabetterfitforInadvertentInterchange.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
25
4.IfneithermaintainingnoreliminatingBALͲ006ispreferred,pleasedescribeyoursuggestionforthedispositionofthis
standard.
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
AnswerComment:
SupporttransferringtoNAESB
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
AnswerComment:
NA
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
26
WilliamSmith
CindyStewart
DougHohlbaugh
RobertLoy
RichardHoag
GroupMemberName
FirstenergyCorp
FirstEnergyCorp.
OhioEdison
FirstEnergySolutions
FirstenergyCorp
Entity
Regio
n
RFC
RFC
RFC
RFC
RFC
Segmen
ts
1
3
4
5
NAͲNot
Applicab
le
6
AnnIvanc
FirstEnergySolutions
FRCC
AnswerComment:
FEsupportsPJMcommentsonthisissue.
ThisquestionisnotapplicableasPJMfeelsthatInadvertentInterchange
requirementsshouldbemovedtoaNAESBstandard.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
AnswerComment:
n/a
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
27
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio
n
BobSolomon
HoosierEnergyRuralElectric
RFC
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC
EllenWatkins
SunflowerElectricPower
SPP
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO
AnswerComment:
WesuggestthattheSDTeliminateBALͲ006.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
1,3,5,6
1,3
1
Segmen
ts
1
28
5.Ifyouhaveanyothercommentsorreliabilityconcerns,pleaseprovidetheminthespacebelow.
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
AnswerComment:
RequirementsinBALͲ006asproposedfordeletionareofvalueina
Standard,seeanswerstoQuestion1and2.
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
AnswerComment:
Ifoursuggestionisnotsupported,wewouldsuggestballotingtheposted
standardandmaketheVRFsandVSLsreflectthefactthatthe
requirementsinthisstandardhavelittleornoimpactonreliability.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
29
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio
n
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
JohnCiza
SouthernCompanyGeneration
SERC
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC
WilliamShultz
SouthernCompanyGeneration
SERC
AnswerComment:
NA
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio
n
DougHils
DukeEnergy
RFC
LeeSchuster
DukeEnergy
FRCC
DaleGoodwine
DukeEnergy
SERC
GregCecil
DukeEnergy
RFC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
Segmen
ts
1
3
5
6
3
5
Segmen
ts
1
6
30
31
DukeEnergy’ssupportfortheeliminationofBALͲ006asaReliability
Standard,andtheaforementionedrequirementstransitiontothe
NAESBstandards,predicatedontheassumptionthattheRealͲtime
reliabilityrequirementsofBALͲ006willbecoveredinoneway(approval
ofproposedBALͲ005Ͳ1)oranother(incorporatedintoanexistingBAL
standard).
GiventhattheproposedBALͲ005Ͳ1willincludearequirementcovering
thecurrentBALͲ006R4,DukeEnergyrecommendsthattheBALͲ005Ͳ1
implementationplanfactorinthepossiblehandoverofBALͲ006
responsibilitiesfromNERCtoNAESBsothatthereisn’tthepossibilityof
BALͲ005Ͳ1beingeffectiveatthesametimethatBALͲ006isstillinplace
withaduplicaterequirement.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
AnswerComment:
AspartofProject2010Ͳ14.2.1Phase2itwassuggestedthatBALͲ006Ͳ2
RequirementR3bemovedintoBALͲ005Ͳ3.WhilePJMagreesitis
importanttocalculateMWhvaluesforInadvertentInterchange,PJM
suggeststhisbemovedtoaNAESBstandard.
Response:
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
Regio Segmen
n
ts
CharlieFreibert
LG&EandKUEnergy,LLC
SERC 3
BrendaTruhe
PPLElectricUtilitiesCorporation
RFC
1
DanWilson
LG&EandKUEnergy,LLC
SERC 5
LinnOelker
LG&EandKUEnergy,LLC
SERC 6
AnswerComment:
LG&EandKUarenotopposedtohandlinginadvertentviaaNAESB
standardorbusinesspractice;theconcernisenforceability.ANAESB
standardorbusinesspracticeforinadvertentwouldlackenforcement
"teeth."ThusLG&EandKUquestionwhetheraNAESBstandardcanas
effectiveltyachievethedesiredresult.
LG&EandKUarenotinfavoroffinancialorFERCestablishedprocesses
forsettlementofaccumulatedinadvertentaccounts.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
32
FirstEnergySolutions
FirstenergyCorp
RFC
RFC
5
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
AnswerComment:
FEsupportsPJMcommentsonthisissue.
AspartofProject2010Ͳ14.2.1Phase2itwassuggestedthatBALͲ006Ͳ2
RequirementR3bemovedintoBALͲ005Ͳ3.WhilePJMagreesitis
importanttocalculateMWhvaluesforInadvertentInterchange,PJM
suggeststhisbemovedtoaNAESBstandard.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
AnswerComment:
n/a
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
RobertLoy
RichardHoag
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
33
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
AnswerComment:
WequestionthepracticeofNERCpostingthissurveywiththe
expectationofanineͲday,weekendincluded,turnaroundforthepossible
eliminationofareliabilitystandard.Thissurveywaspostedduringa
weekwithNERCTechnicalCommitteemeetings,whichlikelyimpacted
theavailabilityofmanyindustryandNERCsubjectmatterexpertsto
providecomments.Wehopethiscondensedcommentingperiodwasan
oversightandaoneͲtimeoccurrence.
Thankyoufortheopportunitytocomment.
Response:
Endofreport
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
34
CommentPeriodEndDate:9/25/2015
CommentPeriodStartDate:9/16/2015
ProjectName:2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControls|BALͲ006Survey
Consideration of Comments
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
1
TheNERCStandardsCommitteeappointedelevenindustrysubjectmatterexpertstoserveontheBARC2periodicreviewteam
(BARC2PRT)inthefallof2013.TheBARC2PRTusedbackgroundinformationonthestandardsandthequestionssetforthinthe
PeriodicReviewTemplatedevelopedbyNERCandapprovedbytheStandardsCommittee,alongwithassociatedworksheetsand
referencedocuments,todeterminewhetherBALͲ006Ͳ2shouldbe:(1)affirmedasis(i.e.,nochangesneeded);(2)revised(which
mayincluderevisingorretiringoneormorerequirements);or(3)withdrawn.Duringthedevelopmentoftherecommendation,the
PRTalsoconsideredstakeholderrecommendationsforcandidateParagraph81requirementsfromPhase1ofParagraph81,and
appliedtheParagraph81criteriatoalloftherequirements.TheteamalsoconsideredtheIndependentExpertReviewPanel
recommendationsonthestandard.
Therewere14responses,includingcommentsfromapproximately43differentpeoplefromapproximately33differentcompanies
representing6ofthe10IndustrySegmentsasshownonthefollowingpages.
Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogiveeverycommentserious
considerationinthisprocess.Ifyoufeeltherehasbeenanerrororomission,youcancontacttheDirectorofStandards,Howard
Gugel(viaemail)orat(404)446Ͳ9693.
SummaryResponse
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
2
TheBARC2.1SDT’srecommendationforretirementofBALͲ006Ͳ0iscontingentonsimultaneousestablishmentofaNERCOperating
CommitteeGuidelinefortheongoingrequiredaccountingofinadvertentinterchange.TheBARC2.1SDTiscoordinatingthe
developmentofsuchaguidelinewiththeNERCOperatingCommittee.
TheBalancingAuthorityReliabilityͲbasedControls2.1StandardDraftingTeam(BARC2.1SDT)reviewedthefindingsoftheBARC2
PrimaryReviewTeam.AsurveywaspostedforcommentSeptember16Ͳ25,2015togainabetterperspectiveastoanyconcernsthe
industrymayhaveifBALͲ006Ͳ2wasretiredandreplacedwithanonͲreliabilityprocess,suchasaguidelineorabusinesspractice.
ThesurveyresponsesindicatedsupportforretirementofBALͲ006Ͳ2asaNERCReliabilityStandard.UponfurtherreviewtheBARC
2.1SDTdeterminedthatBALͲ006Ͳ2doesnotsupportthereliabilityoftheBES.BALͲ006Ͳ2isanaccountingbusinessrequirementand
notareliabilitystandard.ThereforeBALͲ006Ͳ2shouldberetired.
Afteranextensivereview,theBARC2PRTconcludedthatReliabilityStandardBALͲ006Ͳ2wasnotareliabilitystandard,however,
certainprovisionwerenecessaryfortheoperationsoftheInterconnection.
5. Ifyouhaveanyothercommentsorreliabilityconcerns,pleaseprovidetheminthespacebelow.
1—TransmissionOwners
2—RTOs,ISOs
3—LoadͲservingEntities
4—TransmissionͲdependentUtilities
5—ElectricGenerators
6—ElectricityBrokers,Aggregators,andMarketers
7—LargeElectricityEndUsers
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
3
Whenrespondingtothissurveyandprovidingcomments,pleasekeepinmindthatdraftproposedReliabilityStandardBALͲ006Ͳ3hasbeenpostedunder2010Ͳ14.2.1
Phase2ofBalancingAuthorityReliabilityͲbasedControls,inconnectionwithdraftproposedReliabilityStandardsBALͲ005Ͳ1andFACͲ001Ͳ3.ProposedReliabilityStandardBALͲ
005Ͳ1,atRequirementsR1andR8,wouldincludetheobligationscurrentlyunderRequirementR3ofReliabilityStandardBALͲ006Ͳ2.
1
The Industry Segments are:
4. IfneithermaintainingnoreliminatingBALͲ006ispreferred,pleasedescribeyoursuggestionforthedispositionofthis
standard.
3. IfyousupporteliminatingBALͲ006asaReliabilityStandard,areyouinfavoroftheSDTrecommendationthatthese
requirementsbeincludedinacommercialalternativearrangement,suchasaNAESBstandardoraprocessestablishedby
FERC?WhataspectsofBALͲ006shouldberetainedinanalternativearrangement?
2. IfyousupportmaintainingBALͲ006asaReliabilityStandard,areyouinfavorofthePRTrecommendationasnotedinthe
attacheddraftReliabilityStandardBALͲ006?Ifnot,thenwhataspectsofBALͲ006shouldberetainedinastandard?
1. BasedoncommentsrelatedtotheSAR,theIndependentExpertReviewReport,andthePeriodicReviewTeam’
recommendations,theindustryagreesthatBALͲ006isanenergyaccountingstandardandnotaReliabilityStandard,
however,itisunclearwhattheindustrysupportsasareplacement.TheSDThasdevelopedawhitepaperfortheindustry
toconsider.Basedontheconceptswithinthewhitepaper,doyousupportmaintainingReliabilityStandardBALͲ006?1
Questions
8—SmallElectricityEndUsers
9—Federal,State,ProvincialRegulatoryorotherGovernmentEntities
10—RegionalReliabilityOrganizations,RegionalEntities
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
4
5
1.BasedoncommentsrelatedtotheSAR,theIndependentExpertReviewReport,andthePeriodicReviewTeam’
recommendations,theindustryagreesthatBALͲ006isanenergyaccountingstandardandnotaReliabilityStandard,however,
itisunclearwhattheindustrysupportsasareplacement.TheSDThasdevelopedawhitepaperfortheindustryto
consider.Basedontheconceptswithinthewhitepaper,doyousupportmaintainingReliabilityStandardBALͲ006?[1]
[1]Whenrespondingtothissurveyandprovidingcomments,pleasekeepinmindthatdraftproposedReliability
StandardBALͲ006Ͳ3hasbeenpostedunder2010Ͳ14.2.1Phase2ofBalancingAuthorityReliabilityͲbasedControls,inconnection
withdraftproposedReliabilityStandardsBALͲ005Ͳ1andFACͲ001Ͳ3.ProposedReliabilityStandardBALͲ005Ͳ1,atRequirements
R1andR8,wouldincludetheobligationscurrentlyunderRequirementR3ofReliabilityStandardBALͲ006Ͳ2.
LaurelBrandtͲTennesseeValleyAuthorityͲ1,3,5,6ͲSERC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
MaintainBALͲ006(withnochanges)asaReliabilityStandard.
AnswerComment:
ThecurrenteffectiveversionofBALͲ006requiresmeteringatallBAA
interconnectionpoints(R3).TheproposedversionofBALͲ006removes
therequirementformetering.Althoughrequirementformeteringmay
beaddressedinchangestootherBALorFACStandards,untilthatoccurs
BALͲ006shouldremainaswritten.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
Ourpreferenceistoeliminatethisstandardwithonecaveat.Webelieve
BALͲ006shouldbeconvertedtoaguideandplacedintheNERC
OperatingManual.Thetasksdoneunderthisstandardareuseful
housekeepingtasksthatsupportvalidationofbalancingdata.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
6
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
SouthernagreeswiththePRTthatBALͲ006isanenergyaccounting
standardandnotaReliabilityStandard.
Response:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
7
DougHils
LeeSchuster
DaleGoodwine
GregCecil
SelectedAnswer:
AnswerComment:
Regio Segmen
n
ts
DukeEnergy
RFC
1
DukeEnergy
FRCC 3
DukeEnergy
SERC 5
DukeEnergy
RFC
6
EliminateBALͲ006asaReliabilityStandard.
DukeEnergysupportstheeliminationofBALͲ006asaReliability
Standard,basedonthebeliefthattherequirements,withthe
exceptionofcertainprovisionsofR4incorporatedintotheproposed
BALͲ005Ͳ1,arebusinessinnatureandarenotneededtosupportthe
reliableoperationoftheBulkPowerSystem.
Entity
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
WhilePJMagreesitisimportanttomaintainrequirementstocalculate
andaccountforInadvertentInterchange,PJMsuggestthisbemovedtoa
NAESBstandard.
Response:
GroupMemberName
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
8
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
Regio Segmen
n
ts
CharlieFreibert
LG&EandKUEnergy,LLC
SERC 3
BrendaTruhe
PPLElectricUtilitiesCorporation
RFC
1
DanWilson
LG&EandKUEnergy,LLC
SERC 5
LinnOelker
LG&EandKUEnergy,LLC
SERC 6
SelectedAnswer:
ModifyandmaintainBALͲ006asaReliabilityStandard.
AnswerComment:
Inordertomaintainenforcementcapability,BALͲ006shouldremaina
ReliabilityStandard.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
9
FirstenergyCorp
RFC
10
NAͲNot
Applicab
le
6
AnnIvanc
FirstEnergySolutions
FRCC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
FEsupportsPJMcommentsonthisissue.
WhilePJMagreesitisimportanttomaintainrequirementstocalculate
andaccountforInadvertentInterchange,PJMsuggestthisbemovedtoa
NAESBstandard.
Response:
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
RichardHoag
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AdamPadgettͲTECOͲTampaElectricCo.Ͳ1,3,5,6ͲFRCC
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
DonSchmitͲNebraskaPublicPowerDistrictͲ5Ͳ
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
SelectedAnswer:
EliminateBALͲ006asaReliabilityStandard.
AnswerComment:
WebelievetheSDThasprovidedadequateanalysisonsupporting
rationaletoeliminateBALͲ006.InadvertentInterchangeisaddressed
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
11
12
throughotherexistingreliabilityandcommercial
requirements.However,webelievetheSDTcouldhaveprovidedbetter
documentationtosupportitsconclusionsbyidentifyinghoweach
requirementareaddressedindividually.WebelievetheSDTshould
developa“mappingdocument”thataccompaniesitswhitepaperto
bettersubstantiateitsconclusions.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
2.IfyousupportmaintainingBALͲ006asaReliabilityStandard,areyouinfavorofthePRTrecommendationasnotedin
theattacheddraftReliabilityStandardBALͲ006?Ifnot,thenwhataspectsofBALͲ006shouldberetainedinastandard?
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
No
AnswerComment:
Comments:ThepurposelistedinthedraftofBALͲ006hasnotbeen
changedfromthepreviouslyapprovedstandardanddoesnotappear
directlyrelatedtothedraftedrequirements.
TheeliminationofthecurrentlyeffectiveBALͲ006R4inthedraftremoves
arequirementthatnootherstandardaddresses.
Seealsoanswertoquestion1.
Response:
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
AnswerComment:
NAasAZPSdoesnotsupportretainingasaNERCstandard.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
13
GroupName:
SouthernCompany
GroupMemberName
Entity
RobertSchaffeld
SouthernCompanyServices,Inc
JohnCiza
SouthernCompanyGeneration
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
WilliamShultz
SouthernCompanyGeneration
SelectedAnswer:
No
AnswerComment:
WesuggestBALͲ006beretired.
Response:
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
CharlieFreibert
LG&EandKUEnergy,LLC
BrendaTruhe
PPLElectricUtilitiesCorporation
DanWilson
LG&EandKUEnergy,LLC
LinnOelker
LG&EandKUEnergy,LLC
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
Segmen
ts
1
6
3
5
Regio
n
SERC
SERC
SERC
SERC
Segmen
ts
3
1
5
6
Regio
n
SERC
RFC
SERC
SERC
14
AnswerComment:
ToaddressFERC'srecommendationforametrictobindthemagnitudeof
aBA'sinadvertentaccumulation,LG&EandKUsuggestamultiplierof
L10.Forexample,foraBAwithanL10of100,amultiplierof250would
permitanaccumulationofupto25,000MWHs.Thelimitonthe
accumulationneedstoreflecttherelativesizeoftheBA.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
RichardHoag
FirstenergyCorp
RFC
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
SelectedAnswer:
Yes
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
15
SelectedAnswer:
No
AnswerComment:
BPAsupportseliminatingNERCBALͲ006Ͳ2asareliabilitystandardbased
ontheNERCSDT(StandardDraftingTeam)whitepaperprovidedfor
consideration.Asthewhitepapersuggests,thecurrentrequirementsin
NERCBALͲ006Ͳ2ofareliabilitynatureshouldbeaddressedthroughthe
requirementsoftheproposedBALͲ005Ͳ1.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
16
BobSolomon
17
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
PrairiePower,Inc.
SERC 1,3
SunflowerElectricPower
SPP
1
Corporation
GreatRiverEnergy
MRO 1,3,5,6
No
WebelievetheSDThasprovidedadequateanalysisonsupporting
reasonswhyBALͲ006shouldbeeliminated.Wealsobelievethat
Paragraph81criteriacouldbeappliedtoeliminatetheremaining
requirements.BasedonParagraph81CriteriaforAdministrativeand
Reporting,wefeeltheSDThasprovidedsufficienttechnicalbasisto
substantiatethattheserequirementsdo“notsupportreliabilityandis
needlesslyburdensome.”Wealsofeelthatintheinstancewhen
AdjacentBAsdonotagreeuponinterchangequantities,theneedto
reportsuchdisputestoRegionalEntitiesalignswiththedefinitionofthe
Paragraph81ReportingCriterion.Thisspecificcriterionstatesthat
“thesearerequirementsthatobligateresponsibleentitiestoreporttoa
RegionalEntityonactivitieswhichhavenodiscernibleimpacton
promotingthereliableoperationoftheBESandiftheentityfailedto
meetthisrequirementtherewouldbelittlereliabilityimpact.”
Response:
GingerMercier
EllenWatkins
MichaelBrytowski
SelectedAnswer:
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
3.IfyousupporteliminatingBALͲ006asaReliabilityStandard,areyouinfavoroftheSDTrecommendationthatthese
requirementsbeincludedinacommercialalternativearrangement,suchasaNAESBstandardoraprocessestablished
byFERC?WhataspectsofBALͲ006shouldberetainedinanalternativearrangement?
LaurelBrandtͲTennesseeValleyAuthorityͲ1,3,5,6ͲSERC
SelectedAnswer:
Yes
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
SelectedAnswer:
Yes
AnswerComment:
NERCcouldaccomplishthedatacollectionunderrulesofprocedureas
opposedtoareliabilitystandard.
Seeanswerstoquestion1and2forelementsofthecurrentBALͲ006that
wouldneedtobeaddressedinreliabilitystandards.
Response:
NickVtyurinͲManitobaHydroͲ1,3,5,6ͲMRO
SelectedAnswer:
Yes
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
18
SelectedAnswer:
Yes
AnswerComment:
Reconciliationofinadvertent
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
SelectedAnswer:
No
AnswerComment:
WedonotsupportturningthisovertoNAESBorFERC.NAESBbusiness
practicesultimatelybecomepartofatransmissionprovider’stariff.Not
alltransmissionprovidersareBalancingAuthorities.Additionally,notall
BalancingAuthoritiesareFERCjurisdictional.Ratherthancreatinggaps
andmakethedataunverifiable,ourpreferenceisthatBALͲ006be
convertedtoaguideorprocedureandplacedintheNERCOperating
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
19
20
Manual.
Theguidelinesorprocedurecouldbedraftedandmaintainedinthe
operatingmanualbytakingtheexistingverbiageandreplace“shall”with
“will”,“needsto”,or“should”.
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
SelectedAnswer:
No
AnswerComment:
Southernwouldpreferthisbehandledwithagreementsbetweenthe
entities.However,ifastandardisrequired,wesuggestitbewithin
NAESBandnotaNERCReliabilityStandard.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio Segmen
n
ts
DougHils
DukeEnergy
RFC
1
LeeSchuster
DukeEnergy
FRCC 3
DaleGoodwine
DukeEnergy
SERC 5
GregCecil
DukeEnergy
RFC
6
SelectedAnswer:
Yes
AnswerComment:
DukeEnergyrecommendsmovingtheresponsibilitiespresentinR1ͲR3,
aswellasR4.1ofBALͲ006totheNAESBstandards.NAESBalready
handlescertainaspectsofInterchange,andInadvertentaccountingis
consideredtobeabusinesspracticeorcommercialinnature.We
believetherequirementslistedabovefitthatdescription.Wehave
excludedR4frommovingtoNAESB,aswebelieveitwouldbecovered
bytheproposedBALͲ005Ͳ1uponapproval.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
SelectedAnswer:
Yes
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
21
22
PJMbelievestherequirementsinBALͲ006shouldbemovedtoaNAESB
standard.InorderforInadvertentInterchangetobecalculated
appropriatelythestandardshouldincluderequirementssimilartowhat
thePRThassuggestedforBALͲ006.HoweverPJMalsobelievesthat
AdjacentBalancingAuthoritiesshouldoperatetoaNetInterchange
Scheduleasthisisimportanttoavoidmanypotentialdisputeresolutions.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
RobertLoy
FirstEnergySolutions
RFC
5
RichardHoag
FirstenergyCorp
RFC
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
SelectedAnswer:
Yes
AnswerComment:
FEsupportsPJMcommentsonthisissue.
PJMbelievestherequirementsinBALͲ006shouldbemovedtoaNAESB
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
23
standard.InorderforInadvertentInterchangetobecalculated
appropriatelythestandardshouldincluderequirementssimilartowhat
thePRThassuggestedforBALͲ006.HoweverPJMalsobelievesthat
AdjacentBalancingAuthoritiesshouldoperatetoaNetInterchange
Scheduleasthisisimportanttoavoidmanypotentialdisputeresolutions.
Response:
CainBraveheartͲBonnevillePowerAdministrationͲ1,3,5,6ͲWECC
SelectedAnswer:
No
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
SelectedAnswer:
Yes
AnswerComment:
Wesupportmaintainingthecurrentreportingrequirementsthroughthe
CERTSInadvertentInterchangeReportingApplication.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
AdamPadgettͲTECOͲTampaElectricCo.Ͳ1,3,5,6ͲFRCC
SelectedAnswer:
Yes
AnswerComment:
ReferittoNAESBandincorporatealloftheBALͲ006requirementsina
NAESBstandard.
Response:
DonSchmitͲNebraskaPublicPowerDistrictͲ5Ͳ
SelectedAnswer:
Yes
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
24
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
SelectedAnswer:
Yes
AnswerComment:
Weagreethatcommercialalternativearrangements,suchasaNAESB
BusinessPractices,areabetterfitforInadvertentInterchange.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
25
4.IfneithermaintainingnoreliminatingBALͲ006ispreferred,pleasedescribeyoursuggestionforthedispositionofthis
standard.
JeriFreimuthͲAPSͲArizonaPublicServiceCo.Ͳ3Ͳ
AnswerComment:
SupporttransferringtoNAESB
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio Segmen
n
ts
RobertSchaffeld
SouthernCompanyServices,Inc
SERC 1
JohnCiza
SouthernCompanyGeneration
SERC 6
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC 3
WilliamShultz
SouthernCompanyGeneration
SERC 5
AnswerComment:
NA
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
26
WilliamSmith
CindyStewart
DougHohlbaugh
RobertLoy
RichardHoag
GroupMemberName
FirstenergyCorp
FirstEnergyCorp.
OhioEdison
FirstEnergySolutions
FirstenergyCorp
Entity
Regio
n
RFC
RFC
RFC
RFC
RFC
Segmen
ts
1
3
4
5
NAͲNot
Applicab
le
6
AnnIvanc
FirstEnergySolutions
FRCC
AnswerComment:
FEsupportsPJMcommentsonthisissue.
ThisquestionisnotapplicableasPJMfeelsthatInadvertentInterchange
requirementsshouldbemovedtoaNAESBstandard.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
AnswerComment:
n/a
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
27
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio
n
BobSolomon
HoosierEnergyRuralElectric
RFC
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC
EllenWatkins
SunflowerElectricPower
SPP
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO
AnswerComment:
WesuggestthattheSDTeliminateBALͲ006.
Response:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
1,3,5,6
1,3
1
Segmen
ts
1
28
5.Ifyouhaveanyothercommentsorreliabilityconcerns,pleaseprovidetheminthespacebelow.
MatthewBeilfussͲWECEnergyGroup,Inc.Ͳ3,4,5,6ͲMRO,RFC
AnswerComment:
RequirementsinBALͲ006asproposedfordeletionareofvalueina
Standard,seeanswerstoQuestion1and2.
Response:
TerryBIlkeͲMidcontinentISO,Inc.Ͳ2Ͳ
GroupName:
IRCͲSRC
GroupMemberName
Entity
Regio Segmen
n
ts
ChristinaBigelow
ERCOT
TRE
2
KathleenGoodman
ISONE
NPCC 2
BenLi
IESO
NPCC 2
TerryBilke
MISO
RFC
2
GregCampoli
NYISO
NPCC 2
MarkHolman
PJM
RFC
2
CharlesYeung
SPP
SPP
2
AnswerComment:
Ifoursuggestionisnotsupported,wewouldsuggestballotingtheposted
standardandmaketheVRFsandVSLsreflectthefactthatthe
requirementsinthisstandardhavelittleornoimpactonreliability.
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
29
Response:
MarshaMorganͲSouthernCompanyͲSouthernCompanyServices,Inc.Ͳ1,3,5,6ͲSERC
GroupName:
SouthernCompany
GroupMemberName
Entity
Regio
n
RobertSchaffeld
SouthernCompanyServices,Inc
SERC
JohnCiza
SouthernCompanyGeneration
SERC
andEnergyMarketing
RScottMoore
AlabamaPowerCompany
SERC
WilliamShultz
SouthernCompanyGeneration
SERC
AnswerComment:
NA
ColbyBellvilleͲDukeEnergyͲ1,3,5,6ͲFRCC,SERC,RFC
GroupName:
DukeEnergy
GroupMemberName
Entity
Regio
n
DougHils
DukeEnergy
RFC
LeeSchuster
DukeEnergy
FRCC
DaleGoodwine
DukeEnergy
SERC
GregCecil
DukeEnergy
RFC
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
Segmen
ts
1
3
5
6
3
5
Segmen
ts
1
6
30
31
DukeEnergy’ssupportfortheeliminationofBALͲ006asaReliability
Standard,andtheaforementionedrequirementstransitiontothe
NAESBstandards,predicatedontheassumptionthattheRealͲtime
reliabilityrequirementsofBALͲ006willbecoveredinoneway(approval
ofproposedBALͲ005Ͳ1)oranother(incorporatedintoanexistingBAL
standard).
GiventhattheproposedBALͲ005Ͳ1willincludearequirementcovering
thecurrentBALͲ006R4,DukeEnergyrecommendsthattheBALͲ005Ͳ1
implementationplanfactorinthepossiblehandoverofBALͲ006
responsibilitiesfromNERCtoNAESBsothatthereisn’tthepossibilityof
BALͲ005Ͳ1beingeffectiveatthesametimethatBALͲ006isstillinplace
withaduplicaterequirement.
Response:
MarkHolmanͲPJMInterconnection,L.L.C.Ͳ2Ͳ
AnswerComment:
AspartofProject2010Ͳ14.2.1Phase2itwassuggestedthatBALͲ006Ͳ2
RequirementR3bemovedintoBALͲ005Ͳ3.WhilePJMagreesitis
importanttocalculateMWhvaluesforInadvertentInterchange,PJM
suggeststhisbemovedtoaNAESBstandard.
Response:
WayneVanLiereͲPPLͲLouisvilleGasandElectricCo.Ͳ1,3,5,6ͲSERC
AnswerComment:
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
GroupName:
PPLNERCRegisteredAffiliates
GroupMemberName
Entity
Regio Segmen
n
ts
CharlieFreibert
LG&EandKUEnergy,LLC
SERC 3
BrendaTruhe
PPLElectricUtilitiesCorporation
RFC
1
DanWilson
LG&EandKUEnergy,LLC
SERC 5
LinnOelker
LG&EandKUEnergy,LLC
SERC 6
AnswerComment:
LG&EandKUarenotopposedtohandlinginadvertentviaaNAESB
standardorbusinesspractice;theconcernisenforceability.ANAESB
standardorbusinesspracticeforinadvertentwouldlackenforcement
"teeth."ThusLG&EandKUquestionwhetheraNAESBstandardcanas
effectiveltyachievethedesiredresult.
LG&EandKUarenotinfavoroffinancialorFERCestablishedprocesses
forsettlementofaccumulatedinadvertentaccounts.
Response:
RichardHoagͲFirstEnergyͲFirstEnergyCorporationͲ1,3,4,5,6ͲRFC
GroupName:
FERBB
GroupMemberName
Entity
Regio Segmen
n
ts
WilliamSmith
FirstenergyCorp
RFC
1
CindyStewart
FirstEnergyCorp.
RFC
3
DougHohlbaugh
OhioEdison
RFC
4
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
32
FirstEnergySolutions
FirstenergyCorp
RFC
RFC
5
NAͲNot
Applicab
le
AnnIvanc
FirstEnergySolutions
FRCC 6
AnswerComment:
FEsupportsPJMcommentsonthisissue.
AspartofProject2010Ͳ14.2.1Phase2itwassuggestedthatBALͲ006Ͳ2
RequirementR3bemovedintoBALͲ005Ͳ3.WhilePJMagreesitis
importanttocalculateMWhvaluesforInadvertentInterchange,PJM
suggeststhisbemovedtoaNAESBstandard.
Response:
ShawnAbramsͲSanteeCooperͲ1Ͳ
GroupName:
SanteeCooper
GroupMemberName
Entity
Regio Segmen
n
ts
ShawnAbrams
SanteeCooper
SERC 1
JamesPoston
SanteeCooper
SERC 3
MichaelBrown
SanteeCooper
SERC 6
AnswerComment:
n/a
BrianVanGheemͲACESPowerMarketingͲ6ͲNAͲNotApplicable
RobertLoy
RichardHoag
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
33
GroupName:
ACESStandardsCollaborators
GroupMemberName
Entity
Regio Segmen
n
ts
BobSolomon
HoosierEnergyRuralElectric
RFC
1
Cooperative,Inc.
GingerMercier
PrairiePower,Inc.
SERC 1,3
EllenWatkins
SunflowerElectricPower
SPP
1
Corporation
MichaelBrytowski
GreatRiverEnergy
MRO 1,3,5,6
AnswerComment:
WequestionthepracticeofNERCpostingthissurveywiththe
expectationofanineͲday,weekendincluded,turnaroundforthepossible
eliminationofareliabilitystandard.Thissurveywaspostedduringa
weekwithNERCTechnicalCommitteemeetings,whichlikelyimpacted
theavailabilityofmanyindustryandNERCsubjectmatterexpertsto
providecomments.Wehopethiscondensedcommentingperiodwasan
oversightandaoneͲtimeoccurrence.
Thankyoufortheopportunitytocomment.
Response:
Endofreport
ConsiderationofComments|Project2010Ͳ14.2.1Phase2ofBARC|BALͲ006Survey
EnterdateCofCwillbepostedhere:
34
Standards Announcement
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Formal Comment Period Open through January 11, 2016
Now Available
A formal comment period for BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility
Interconnection Requirements, and the recommended retirement of BAL-006-2 – Inadvertent
Interchange is open through 8 p.m. Eastern, Monday, January 11, 201.
The standard drafting team’s considerations of the responses received from the last comment period
are reflected in these drafts of the standards.
Commenting
Use the electronic form to submit comments on the standards. If you experience any difficulties in
using the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
If you are having difficulty accessing the Standards Balloting & Commenting System due to a
forgotten password, incorrect credential error messages, or system lock-out, contact NERC IT support
directly at [email protected] (Monday – Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot for the three standards and a non-binding poll of the associated Violation Risk
Factors and Violation Severity Levels for FAC-001-3 will be conducted December 31, 2015 through
January 11, 2016.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
11/10/2015
1/11/2016
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 Non-binding Poll IN 1 NB
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1 IN 1 ST
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-006-2 IN 1 ST
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 IN 1 ST
Comment Period Start Date:
Comment Period End Date:
Associated Ballots:
There were 43 sets of responses, including comments from approximately 117 different people from approximately 84 companies
representing 8 of the 10 the Industry Segments as shown in the table on the following pages.
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls | BAL-005-1, BAL-006-2 & FAC-001-3
Project Name:
Comments Received Report
4. If you are not in support of the proposed modifications to FAC-001-3, please provide your objection(s) and proposed solution(s) in the area
below.
3. If you are not in support of the retirement of BAL-006-2 and the development of a guideline, please provide your objection(s) and proposed
solution(s) in the area below.
2. If you are not in support of the proposed modifications to BAL-005-1, please provide your objection(s) and proposed solution(s) in the area
below.
1. The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide sufficient
clarity? If not, please explain in the comment area below.
Questions
6
Brian Van
Gheem
ACES Power
Marketing
Segment(s)
2
Name
Albert
PJM
Interconnection, DiCaprio
L.L.C.
Organization
Name
NA - Not
Applicable
RFC
Region
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
Greg Campoli
Ali Miremadi
Terry Bilke
Liz Axson
ACES Power
Marketing
ACES Power
Marketing
ACES Power
Marketing
ACES Power
Marketing
ACES Power
Marketing
ACES Power
Marketing
Ellen Watkins
Michael
Brytowski
John Shaver
John Shaver
Shari Heino
Kevin Lyons
1
1,5
1
4,5
1,3,5,6
1
1,3
PJM
2
Interconnection,
L.L.C.
Kathleen
Goodman
ACES Power
Marketing
PJM
2
Interconnection,
L.L.C.
Mark Holman
1
PJM
2
Interconnection,
L.L.C.
Ben Li
ACES Power
Marketing
2
PJM
Interconnection,
L.L.C.
Group
Member
Segment(s)
Charles Yeung
Group Member Group Member
Name
Organization
ACES
Bob Solomon
Standards
Collaborators Ginger Mercier
ISO
Standards
Review
Committee
Group Name
MRO
TRE
WECC
WECC
MRO
SPP
SERC
RFC
TRE
RFC
WECC
NPCC
NPCC
RFC
NPCC
SPP
Group Member
Region
Kelly Dash
Kelly Dash
6
1,2,3,4,5,6
Emily
Rousseau
MRO
Dominion Louis Slade
Dominion
Resources, Inc.
5
Colby Bellville 1,3,5,6
Duke Energy
Lower Colorado Dixie Wells
River Authority
Chris Scanlon 1
Exelon
NPCC
MRO
Dominion
Con Edison
MRO
Amy Casucelli
Randi Heise
NA - Not
Applicable
1,3,5,6
1,3,5,6
1,3,5
3,4,5,6
1,3,5,6
4
Dominion 5,6
Dominion
Resources, Inc.
Kelly Dash
MRO
Tony Eddleman
Edward Bedder
MRO
Tom Breene
Kelly Dash
MRO
Terry Harbour
Kelly Dash
MRO
Scott Nickels
1,5
MRO
Brad Perrett
1,3,5,6
1,3,5,6
MRO
Mahmood Safi
4
MRO
MRO
Larry Heckert
1,6
Mike Brytowski
MRO
Jodi Jenson
1,3,5,6
2
MRO
Kayleigh
Wilkerson
NPCC
NPCC
NPCC
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
1,3,5
1,3,5,6
MRO
1
Shannon Weaver MRO
MRO
Dave Rudolph
MRO
TRE
TRE
TRE
RFC
SERC
FRCC
RFC
RFC
RFC
3,4,5,6
Lower Colorado 5
River Authority
Dixie Wells
6
Lower Colorado 1
River Authority
Duke Energy
Greg Cecil
5
Teresa Cantwell
Duke Energy
Dale Goodwine
3
Lower Colorado 6
River Authority
Duke Energy
Lee Schuster
1
3
1
Michael Shaw
Duke Energy
Exelon
John Bee
Doug Hils
Exelon
Chris Scanlon
MRO-NERC Joe Depoorter
MRO
Standards
Review Forum Chuck Lawrence MRO
(NSRF)
Chuck Wicklund MRO
LCRA
Compliance
FRCC,RFC,SERC Duke Energy
Exelon
Utilities
Southern
Company Southern
Company
Services, Inc.
Marsha
Morgan
1,3,5,6
SERC
Southern
Company
Southern
Company Southern
Company
Services, Inc.
5
3
William Shultz
Dominion 5
Dominion
Resources, Inc.
Russell Deane
Southern
Company Southern
Company
Services, Inc.
Dominion 5
Dominion
Resources, Inc.
Jeffrey N Bailey
R Scott Moore
Larry W Bateman Dominion 1,3
Dominion
Resources, Inc.
6
Dominion 1,3
Dominion
Resources, Inc.
Candace L
Marshall
Southern
Company Southern
Company
Services, Inc.
SERC
Dominion 1,3
Dominion
Resources, Inc.
Larry Nash
John Ciza
SERC
Dominion 5
Dominion
Resources, Inc.
Nancy Ashberry
1
SERC
Dominion 5
Dominion
Resources, Inc.
Chip Humphrey
Robert Schaffeld Southern
Company Southern
Company
Services, Inc.
RFC
5,6
Dominion Dominion
Resources, Inc.
Louis Slade
SERC
SERC
SERC
SERC
NPCC
SERC
RFC
SERC
SERC
Dominion 1,3,5,6
Dominion
Resources, Inc.
Connie Lowe
Northeast
Power
Coordinating
Council
Ruida Shu
1,2,3,4,5,6,7
NPCC
RSC no UI
O&R
NA - Not
Applicable
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Guy Zito
Brian Shanahan
Rob Vance
Mark J. Kenny
Gregory A.
Campoli
Randy
MacDonald
Wayne Sipperly
David
Ramkalawan
Glen Smith
Brian O'Boyle
Brian Robinson
5
5
4
4
4
2
2
1
1
1
1
Paul Malozewski Northeast
Power
Coordinating
Council
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
1
1
2
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Helen Lainis
Michael Jones
Silvia Parada
Mitchell
Connie Lowe
Michael Forte
Sylvain Clermont Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Kathleen M.
Goodman
Si Truc Phan
Kelly Silver
Brian O'Boyle
5
3
4
4
3
2
2
7
Northeast
Power
Coordinating
Council
Alan Adamson
6
Northeast
Power
Coordinating
Council
Bruce Metruck
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
Southwest
Power Pool,
Inc. (RTO)
Shannon
Mickens
2
SPP
Southwest
Power Pool,
Inc. (RTO)
Southwest
Power Pool,
Inc. (RTO)
Southwest
Power Pool,
Inc. (RTO)
Southwest
Power Pool,
Inc. (RTO)
Jason Smith
Jim Nail
Mike Kidwell
Kevin Giles
SPP
Shannon Mickens Southwest
Standards
Power Pool,
Inc. (RTO)
Review Group
1,3,5,6
1,3,5
SPP
SPP
SPP
SPP
2
3,5
SPP
2
No
0
0
No
Dislikes
Likes
0
0
The definition of AGC is fine, but in the process of combining the need for common sources regarding MW and MWh values into the proposed R7, the
association between AGC, ACE, MW, and MWh quantities is less clear. The user now has to combine the definitions for AGC, Reporting ACE, and R7
to get an equivalent picture compared to the original requirement. Maybe some references or revised wording in R7 would help clarify the expectations.
Comment
Document Name
Answer
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Response
Dislikes
Likes
SRP recommends removing or defining terms capitalized but not defined in the NERC Glossary of Terms such as Control Area and Balancing Area.
Capitalizing terms that are not defined creates confusion even when used in the rationale areas.
Primary Inadvertent Interchange is not a NERC defined term. It is a defined WECC term, SRP recommends adding Primary Inadvertent Interchange to
the terms used continent wide. as the revised ATEC definition will be effective continent wide.
The proposed definition of AGC combines defined terms to create the phrase “Balancing Authority Area Demand” ERC recommends rephrasing the
definition to avoid using one defined term to modify another. An alternative might be “Demand within a Balancing Authority Area”.
Modifying the definition of Balancing Authority would misalign the term with the definition found in the NERC Rules of Procedure. SRP recommends
retaining the current definition of Balancing Authority.
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
1. The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide sufficient
clarity? If not, please explain in the comment area below.
No
0
0
No
0
0
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Response
Dislikes
Likes
7.2. a time synchronized common source to determine hourly megawatt
䇲㼔㼛㼡㼞㻌㼢㼍㼘㼡㼑㼟㻌㼍㼓㼞㼑㼑㼐䇲
mitigation
of errors. 㼡
7.1. a common source to provide information to both Balancing Authorities for the scan rate values used in the calculation of Reporting ACE; and,
7. Each Balancing Authority shall ensure that each Tie
䇲㻸㼕㼚㼑㻘㻌㻼㼟㼑㼡㼐㼛䇲
nd
Dynamic Schedule
㼀㼕㼑㻘㻌㼍 with an Adjacent Balancing Authority that is
included in the ACE equation is equipped with: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
HQT believes that Requirement 7 should apply specifically to tie lines, pseudo-ties and dynamic schedules that included in the ACE equation. Even
though having the same scan-rate measure and having a time synchronized common source is a good practice, Tie-lines that are not included in the
ACE equation that are not equipped with such will not affect adversely the control of a balancing authority. HQT proposes to modify R7 as below:
Comment
Document Name
Answer
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Response
Dislikes
Likes
We feel that the above definition adds clarity, and with the addition of the term automatically in the definition, more adequately describes the function
that AGC provides.
Automatic Generation Control (AGC): A process designed and used to automatically adjust a Balancing Authority Area’s Demand and resources to help
maintain the Reporting ACE of a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.
Duke Energy suggests a modification to the proposed definition of Automatic Generation Control (AGC), which we feel would enhance clarity and
maintains the assumed intent of the drafting team. We recommend the following:
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Response
No
0
0
Document Name
Answer
No
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Response
Dislikes
Likes
“Demand” is defined in the NERC Glossary as the rate at which energy is used by the customer. As written, the AGC definition could be interpreted to
mean a BA is required to utilize Demand controls to adjust ACE. A BA should not be expected to use Demand controls to adjust ACE because the realtime nature of ACE and some current forms of Demand controls are not necessarily compatible. Additionally, the SDT’s proposed definition does not
mention Interchange which is a component of ACE and can be used to adjust ACE. Because Interchange has not typically been understood to be
included in the term “resources,” LG&E/KU recommend “Interchange” be expressly included in the definition of AGC. If the SDT does not accept the
above recommendation, should it be the industry’s understanding that the term “resources” includes Interchange?
Automatic Generation Control (AGC): A process designed and used to adjust a Balancing Authority Area’s Demand, Interchange, or resources, as
applicable, to help maintain the Reporting ACE of a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.
Comments: LG&E/KU recommend the AGC definition be modified to add flexibility as follows:
No X
Yes
The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide sufficient
clarity? If not, please explain in the comment area below.
These comments are submitted on behalf of Louisville Gas and Electric Company and Kentucky Utilities Company (“LG&E/KU”) LG&E/KU
are registered in the SERC region for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP,
and TSP.
Comment
Document Name
Answer
0
0
No
0
0
Comment
Document Name
Answer
No
William Hutchison - Southern Illinois Power Cooperative - 1
Response
Dislikes
Likes
Regarding the modified definition of Pseudo-Tie, BPA requests clarification of what constitutes an "alternate control process."
BPA disagrees with the modified definition of AGC; AGC is equipment or a system, not a process. Also, BPA suggests that the clause "...in that of a
BAA..." could be simplified to "in a BAA."
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Response
Dislikes
Likes
If the SDT does move forward with the proposed changes to the AGC definition, Texas RE recommends revising the proposed definition slightly to
correct what appears to be a typographical error. Specifically, Texas RE believes the phrase “that of” should be struck so that the proposed AGC
definition reads: “A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in a
Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.”
Texas RE recommends that the SDT consider the impact of changing the definition of Automatic Generation Control (AGC) on other NERC Glossary
definitions prior to implementing such a change in this project. Although the SDT’s stated goal of converting the AGC definition from a prescriptive “how
to” requirement to an arguably more flexible, performance-based approach is laudable, Texas RE notes that AGC is used in other NERC Glossary
definitions and, as currently defined, represents a commonly understood term in the industry. For example, the term AGC is used in the following
defined terms: Anti-Aliasing Filter, Overlap Regulation Service, and proposed Remedial Action Scheme. Accordingly, modifying the AGC definition in
one context without considering the consequences of such a change for other defined terms could introduce unnecessary uncertainty and confusion, as
well as lead to unintended consequences. In light of the interlocking usage of AGC, Texas RE recommends that the SDT either retain the existing AGC
definition or, at a minimum, consider the impact of changing the AGC definition as part of this project prior to making any changes.
Comment
0
0
Yes
0
0
Yes
0
0
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Response
Dislikes
Likes
Please check and revise as appropriate.
“A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a Balancing
Authority within the bounds required by applicable NERC Reliability Standards.”
The phrase “..help maintain the Reporting ACE in that of a Balancing Authority Area …” in the revised definition reads a bit awkward. We interpret the
definition is meant to be:
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Response
Dislikes
Likes
A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a Balancing
Authority Area within the bounds required by applicable NERC Reliability Standards.
Southern suggests the below change to the definition of AGC:
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Response
Dislikes
Likes
0
0
Yes
Yes
0
0
0
0
Yes
Document Name
Answer
Yes
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
We would suggest to the drafting team to develop a rationale box for the modification of the Pseudo Tie definition as they did for the AGC definition. We
feel this would help provide clarity on why the drafting team made the modifications to this term’s definition and how this change will have an impact on
the reliability of the BES.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Response
Dislikes
Likes
N/A
Comment
Document Name
Answer
0
0
0
0
Yes
0
0
Yes
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
Yes
Jeremy Voll - Basin Electric Power Cooperative - 3
Response
Dislikes
Likes
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Response
Dislikes
Likes
Comment
Document Name
Answer
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Response
Dislikes
Likes
Comment
0
0
Yes
0
0
Yes
0
0
Comment
Document Name
Answer
Douglas Webb - Douglas Webb
Response
Dislikes
Likes
Comment
Document Name
Answer
Yes
Yes
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Response
Dislikes
Likes
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
0
0
0
0
Yes
0
0
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Yes
Yes
Laura Nelson - IDACORP - Idaho Power Company - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. - 3
Response
Dislikes
Likes
0
0
Yes
0
0
Yes
0
0
Comment
Document Name
Answer
William Temple - William Temple
Response
Dislikes
Likes
Comment
Document Name
Answer
Yes
Yes
Shivaz Chopra - New York Power Authority - 6
Response
Dislikes
Likes
Comment
Document Name
Answer
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Response
Dislikes
Likes
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
0
0
0
0
Yes
0
0
Yes
Likes
0
Please check and revise as appropriate.
“A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a
Balancing Authority within the bounds required by applicable NERC Reliability Standards.”
The phrase “..help maintain the Reporting ACE in that of a Balancing Authority Area …” in the revised definition reads a bit awkward. We
interpret the definition is meant to be:
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Response
Dislikes
Likes
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
Response
Dislikes
Likes
0
0
0
0
0
0
0
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
Response
Dislikes
Likes
Comment
Document Name
Answer
Glenn Pressler - CPS Energy - 1,3,5
Response
Dislikes
Likes
Comment
Document Name
Answer
Tammy Porter - Tammy Porter
Response
Dislikes
Likes
Comment
Document Name
Answer
Louis Slade - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Response
Dislikes
0
0
0
0
0
0
Dislikes
Likes
0
Comment
0
Document Name
Answer
Anthony Jablonski - ReliabilityFirst - 10
Response
Dislikes
Likes
Comment
Document Name
Answer
Jonathan Appelbaum - United Illuminating Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Chris Scanlon - Exelon - 1, Group Name Exelon Utilities
Response
Dislikes
Likes
Comment
Document Name
0
0
0
0
0
0
Document Name
Answer
Teresa Czyz - Georgia Transmission Corporation - 1,3 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Response
0
0
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
Jason Snodgrass - Georgia Transmission Corporation - 1
Response
Dislikes
Likes
Comment
0
0
(1) We continue to have concerns with Requirement R4 and the approach taken in the wording of this requirement. We agree with the SDT that bad
data quality will lead to an inaccurate ACE calculation. However, we feel the SDT should move away from concerns over data quality and instead focus
on Reporting ACE calculation capabilities, as it is used by System Operators as a primary metric in making critical operating decisions.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Response
Dislikes
Likes
In R7.2, many dynamic schedules do not have MWH meters; the MWH value is simply the integrated scan rate data for the dynamic schedule. BPA
proposes 7.2 be modified to read:
7.2 for all Tie-Lines and metered Psuedo-Ties and metered Dynamic Schedules, a time-synchronized common source to determine hourly megawatthour values agreed upon to aid in the identification and mitigation of errors.
In R7.1 BPA requests “information....for the scan rate values used in the calculation of Reporting ACE” be defined. BPA is unsure how to address the
dynamic schedule portion of this requirement.
R6: BPA still has concerns as to how R6 would be met. This requirement seems subjective and open-ended; it would be difficult for an auditor to apply
a consistent metric or method to validate compliance. BPA proposes the following: “Each Balancing Authority that is within a multiple Balancing
Authority Interconnection shall implement an Operating Process to ensure the accuracy of scan-rate data used in the calculation of Reporting ACE for
each Balancing Authority Area. The process must accomplish the following:
a. Compare MWh values from common source meters to integrated scan rate values
b. Xxx
c. Xxx
R1: BPA requests definition of “design scan rate” as identified in the R1. Scan rate is not a defined term in the NERC Glossary. It is unclear to what the
SDT means by design scan rate and why the word “design” was added in this second draft.
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
2. If you are not in support of the proposed modifications to BAL-005-1, please provide your objection(s) and proposed solution(s) in the area
below.
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0
0
0
In R6 the SDT is using a new term called “scan rate data” which is not a defined term. This term is rather ambiguous. The phrase “affecting the
accuracy of data” is clear enough. Or possibly say the accuracy of data used in calculating ACE. In 7.1 the SDT uses a term called “scan rate
values”. The scan rate is how fast we collect the data, it is not the type of data used here. All SCADA data has a scan rate, this could really be referring
to almost anything.
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Response
Dislikes
Likes
We have a concern pertaining to Requirement R3 parts 3.1 and 3.2. Our group would suggest that the drafting team provide clarity on what are the
intents for this particular Requirement and its parts. At this particular time, we are interpreting that the frequency source has to be within 1mHz accuracy
for 99.95% of the year.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Response
Dislikes
Likes
(4) The SDT assumes that all tie lines between Balancing Authorities use time-synchronized meters. This may not always be true. We recommend
the removal of the term “time synchronized” in Requirement R7, Part 7.2 and allow Balancing Authorities to continue to operate to a common source
when conducting their end-of-hour checks with their Adjacent Balancing Authorities. We also recommend the expansion of the VSLs for Requirement
R7 where failure to meet one part would be High, and failure to meet both would be Severe.
(3) We suggest that Requirement R5 be removed because there is an equally efficient and suitable manner of achieving the reliability result through
the NERC Event Analysis (EA) Process. The EA Process, category 1h, requires entities to report when there is a loss of monitoring or control at a
Control Center, and could include Reporting ACE calculation capabilities. Hence, this requirement would then be unnecessary.
(2) The term “operator” in Requirement R4 is too broad and the SDT should replace it with “System Operator.” When we previously identified this as a
concern, the SDT’s response was that “By using the term operator, the BA will assure the information is provided to the correct personnel.” Balancing
Authorities are already required to identify such personnel as System Operators in PER-003-1 R3. The SDT should use the System Operator glossary
term to align with other reliability requirements and to avoid confusion.
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Texas RE noticed R6 does not address a single Balancing Authority Interconnection. Texas RE recommends there be a requirement for an Operating
Process to identify and mitigate errors affecting the accuracy of scan rate data used in calculating Reporting ACE even in single Balancing Authority
Interconnections.
Requirement R6: Singe Balancing Authority Interconnection
As previously submitted for the initial ballot, Texas RE recommends the SDT use the term “System Operator” in R4. The rational states “System
operators utilize Reporting ACE as a primary metric to determine operating actions or instructions. When data inputs into the ACE calculations are
incorrect, the operator should be made aware through visual display. When an operator questions the validity of the data, actions are delayed and the
probability of adverse events occurring can increase.” The definition of System Operator is “An individual at a control center (Balancing Authority,
Transmission Operator, Generator Operator, Reliability Coordinator) whose responsibility it is to monitor and control that electric system in real
time.” The response provide by the SDT to this issue was “The SDT thanks you for your comment. However, the SDT believes that the term System
Operator is too broad and may not address the correct personnel. By using the term operator, the BA will assure the information is provided to the
correct personnel.” A System Operator needs to be aware of any data issues to make the correct decisions. A BA can provide the information to any
other personnel it so desires but the System Operator must, at a minimum, have access to the Reporting ACE information. As written, and interpreted
by the SDT, there could be possible gaps in providing the individuals whose responsibility it is to monitor and control that electric system in real time
correct information. There may not be consistency within Balancing Authorities as to who the “operator” is in this requirement. Texas RE suggests the
verbiage “System Operator and other personnel (as determined by the BA)” to provide clarity. As is, if a System Operator does not have the information
the Balancing Authority will be compliant but may hinder reliability by delaying actions and increasing the probability of adverse events occurring. The
non-definitive term “operator” will inherently inject non-uniformity in determining compliance. Each entity will have a different interpretation of what
“operator” means which will appear as an inconsistency in the Regional Entity review. If an “operator” who is not a System Operator is making and
acting on decisions that control the electric system in real time, is that not a concern of the SDT?
Requirement R4: System Operator
In reading Requirement R1 and M1, it is unclear whether or not there is a requirement to utilize a scan rate. R1 indicates “The Balancing Authority shall
use a design scan rate…” This almost looks like it should read “The Balancing Authority shall use a scan rate” OR “The Balancing Authority shall
design a scan rate”. Texas RE recommends there be a requirement to both design and utilize a scan rate as it increases the integrity of data during
events as indicated by the rationale.
Requirement R1: Scan Rate
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Response
Dislikes
Likes
0
0
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Response
Dislikes
Likes
The VSL for R4 should reflect System Operators.
Texas RE notes that some of the proposed changes to the Standard language have not been flowed through to all proposed VSLs. Texas RE
recommends that the SDT review this language and ensure that the final Standard language is accurately reflected in the corresponding VSLs. For
example, in the VSLs for R2 there were only corrections in the Lower VSL language to capture changes in the Standard. The changes should be
reflected in the other VSLs associated with R2.
VSL Language
The BAL-005-1 Implementation Plan lacks clarity on effective dates for the Standards and definitions in question. BAL-001-2 is effective July 1,
2016. There may not be an approval on definitions contained within BAL-005-1 (effectively BAL-005-1 itself unless the SDT has some other
unapproved process in mind) before that time period. Additionally the SDT is unclear if the definitions would apply to BAL-005-0.2b, which could still be
in effect after BAL-001-2 is in effect but before BAL-005-1 becomes effective. A CEA will have to evaluate the Standards and definitions that are FERC
approved, not proposed, for compliance monitoring efforts.
Implementation Plan
Texas RE recommends changing the verbiage from “each calendar year” to “each rolling 12 month period”. Specifically, R3 and R5 include the term
“calendar year” which implies Jan 1 to Dec 31. Therefore, if a CEA evaluates compliance to the Requirement in mid-year, there cannot be an assertion
of compliance for the current year. Consequently, if the CEA returns in two years, the half year’s period of data should be available to ascertain
compliance (per the Evidence Retention statements) but the BA may not provide the data based on the RoP Appendix 4C Section 3.1.4.2). Texas RE
considers this as a gap in compliance monitoring (and reflect a possible gap in reliability). The SDT assertion that “Since an Audit Period will include at
least one entire calendar year” is incorrect. A BA has to be audited AT LEAST once every three years but may be audited more often as needed. As
written the BA is non-compliant, per the VSLs, until a calendar year is complete.
Calendar Year
Texas RE recommends the standard language explicitly state how DC ties should be handled rather than indicating an exclusion. In the SDT’s comment
responses for Texas RE’s comments on the initial ballot, the SDT states “In the definition of Reporting ACE asynchronous DC ties between
Interconnections are excluded from Reporting ACE and are handled as either a generator or load” and “Reporting ACE has been redefined to require
that all DC asynchronous tie lines with other interconnections be represented as Source
䇲㻿
written requirement for the DC ties to be handled in any way.
Reporting ACE
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Tacoma Power assumes that the intent of Requriement R3, Part 3.1, is that the total complement of frequency metering equipment meets the
availability specification. For example, if one frequency metering equipment has an availability of 99.94%, but there is another frequency metering
equipment available as a fail-over source such that availability of the redundant sources together is equal to or higher than 99.95%, this should be
considered compliant. Is this assumption reasonable?
Comment
Document Name
Answer
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Response
Dislikes
Likes
The VRF for R5 is listed as “Medium.” This appears to be an administrative function to calculate an entities prior year performance and should be
assigned a VRF of “Lower.”
BAL-005-2 R4 and R6 appear to be duplicative with R2 in the draft version of TOP-010-1. Reporting ACE and the inputs to it are obviously Real-time
data necessary to perform Real-time monitoring of the BES. LG&E/KU recommend that R4 and R6 be removed from the BAL-005-2 standard and allow
TOP-010-1 R2 to be the single Balancing Authority requirement addressing implementation of an Operating Process or Procedure for Real-time data
(which includes Reporting ACE and the scan rate data used to calculate Reporting ACE) quality issues.
Frequency is a very important reliability parameter that should be monitored by the Balancing Authority. Currently, BAL-005.02b R8.1 requires that
frequency metering be available 99.95% of the time. However, R3 of proposed BAL-005-2 requires frequency metering to be available 99.95% of the
time “for the calculation of Reporting ACE.” This added wording appears to create a possible overlap compliance concern with R5. All Balancing
Authorities understand the importance of redundant frequency metering and are today required to maintain an availability (through automatic failover) of
99.95%. However, per the latest proposed BAL-005-2 standard not only does frequency need to be available as a reliability parameter but it must be
available “for the calculation of Reporting ACE.” If the “system used to calculate Reporting ACE” (addressed in R5) is unavailable then a Balancing
Authority could be found non-compliant with both R3 and R5 despite having maintained frequency monitoring availability for any purpose at or above
99.95%. When compared to today’s requirement to maintain a frequency monitoring availability of 99.95%, adding “for the calculation of Reporting ACE”
provides no reliability benefit given that the availability of the “system used to calculate Reporting ACE” is required to be 99.5%. LG&E/KU recommends
removing the language “for the calculation of Reporting ACE” from R3 as this added language provides no additional reliability benefit.
Requirement 3:
LG&E/KU have recommended a change to the proposed AGC definition and provided an explanation in the “comments” section for question 1. Other
comments regarding BAL-005-1 follow.
Comment
0
0
We therefore once again urge the drafting team to consider retiring Requirements R1, R3, R4, R5 and R7 from BAL-005, and map them into
Organization Certification Requirements. While argument can be made to retain R6 as it drives the proper behavior to ensure data errors are detected
and mitigated, consideration may be given to also include this in the Organization Certification Requirements.
If arguments are made to have these requirements specifically stipulated, then such argument can be extended to include every data and tool that an
operating entity (including RC, TOP and GOP) uses to perform all of its tasks. If that’s the case, there will be no end to the scope of this extension as
this may include such data as PMU data, RTU data, voltage, current, MW, Mvar, frequency, etc., and tools such as on-line contingency analysis, EMS
programs, line loading estimators, load flow programs, dynamic simulation software, etc. For years, operating entities have been relying on these data
and tools to perform their tasks, and there have not been any notable events that occurred due to inaccurate data or tool capability.
We continue to disagree with the majority of the requirements in the standard that stipulate the capabilities that a BA must have in order to perform its
reliability tasks. In our view, these are more suited for inclusion in the Organization Certification Requirements as opposed to in Reliability Standards.
The ongoing process to ensure accuracy of operating information and tools is an essential component of any operating entity which provide such
services and register with NERC as the responsible entity for complying with applicable Reliability Standards. To have explicit requirements for having
accuracy metering data at specific scan rate and availability (R1, R3 and R5), flagging missing or invalid data (R4), having a process in place to detect
and mitigate inaccurate or missing information (R6), and using common source information between adjacent BAs (R7) are the fundamental
organization requirements to enable a BA (and any operating entity) perform its reliability tasks to meet its basic obligations.
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Response
Dislikes
Likes
Tacoma Power assumes that the intent of Requirement R7, Parts 7.1 and 7.2, is not to address the real-time status of common sources, for either scan
rate values or hourly megawatt-hour values, or for loss of time synchronization. It seems that these real-time issues would be addressed under
Requirement R2, Requirement R6, and/or other requirements and would not necessarily constitute a violation of Requirement R7.
Could the drafting team please clarify how compliance with Requirement R3, Part 3.2, would be addressed if a Balancing Authority periodically tests
frequency metering equipment (e.g., annually) and finds that the equipment has fallen out of calibration since the last test? For example, in the case of
analog frequency transducers, in particular, the accuracy could stray over time. If a Balancing Authority tests its frequency metering equipment
periodically and discovers that the accuracy is now less than 0.001 Hz, the Balancing Authority should not be in violation, since, in this scenario, it is not
reasonable for them to have identifed the inaccuracy before the frequency metering equipment went out of calibration.
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REQUIREMENT 2
Additionally, if this standard is to remain, then the name of the standard should be changed. It is now referred to as Balancing Authority Control, but
the requirements are for ACE Process Design. BA Control is addressed by BAL requirements - not by this standard.
The new R1 is a design requirement and not something that is subject to change.
REQUIREMENT 1
PJM proposes that BAL-005 be translated into a certification requirement for the following reasons:
Comment
Document Name
Answer
William Temple - William Temple
Response
Dislikes
Likes
In the definition of Actual Net Interchange, strike the last sentence since it is too prescriptive. We believe a BA should have the flexibility to either
include or exclude the actual transfers across DC tie lines based on the modeling of the facility.
There was concerns about what quality the ± 0.001 Hz was being applied to.
3.3 checked for accuracy once each calendar year
3.2 that is rated to, and has a metering accuracy with a precision to ± 0.001 Hz.
3.1 that is available a minimum of 99.95% for each calendar year
R3. Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE:
CO-1 recommend the following wording for R3:
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area is included
within its metered boundaries.”
R1 from BAL-005-0.2b should be retained in BAL-005-1 and re-written as follows:
R3 could also be misinterpreted to mean that a BA’s frequency error over an entire year must be 0.001 HZ or less.
The term “scan-rate” should be changed to “scan rate.” Nowhere else in the standard or the NERC glossary is this term hyphenated.
Requirement R6 is confusing regarding the term “errors.” Are these metering errors such as spikes? Are these Inadvertent Interchange metering errors?
The requirement should provide more clarity on this.
On the other hand, it is possible to have a process to handle no ACE values.
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process.” Is it more important
to have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
3.2 that is rated to, and has a metering accuracy with a precision to ± 0.001 Hz.
3.1 that is available a minimum of 99.95% for each calendar year
R3. Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE:
PJM believes the requirement should be removed. However if the requirement is not removed PJM submits the following re-wording of R3 for clarity:
b.
a. With the way R3 reads, it could be misinterpreted that the frequency metering equipment requires an accuracy of 0.001 Hz for 99.95% of the
calendar year. That would mean checking (and fixing) your frequency metering device every hour to ensure you do not exceed four hours during a year
with a frequency accuracy less than 0.001 Hz. This is not intent of R3 and the requirement should be rewritten. The intent is that the frequency
metering equipment is designed to have a minimum accuracy of 0.001 Hz.
There are two concerns with the way R3 is worded:
If an availability requirement is needed, then we suggest tie it into the same time frame as the loss of ACE mandate.
Average availability (R3.1) on the other hand creates a reliability gap, and that as written does not increase reliability. Every lost scan must be saved
and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making maintenance decisions, but as a
standard use of average availability could be seen as establishing a reliability gap since some could even say this is not a good use of computer time.
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable requirement? PJM suggests
that frequency meter accuracy be included in the certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good practice that when a BA control center is not functional that it tells the RC, but this is covered elsewhere. IRO-005-3.1a R1.6 requires the
RC monitor “Current ACE for all its Balancing Authorities. ”
This requirement is not a reliability-based standard and is not needed. R2 addresses reporting the loss of ACE to an RC. The rationale states this is
important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and NET Interchange). If a BA can’t compute its
own ACE, then one of those three quantiles is unavailable. The RC does not rely on the BA for frequency. NET tie flow is not used in any reliability
studies (whereas individual tie flows would come from the TO) and NET Interchange is a market issue - not a reliability issue.
0
0
䇲㼔㼛
If for any reasons Requirement R3 is retained, then we would suggest rewording it to improve clarity. As written, R3 can be interpreted as a
continuous accuracy requirement of 0.001 Hz under all conditions including use of secondary or tertiary backup equipment when necessary
We therefore once again urge the drafting team to consider retiring Requirements R1, R3, R4, R5 and R7 from BAL-005, and map them into
Organization Certification Requirements. While argument can be made to retain R6 as it drives the proper behavior to ensure data errors are
detected and mitigated, consideration may be given to also include this in the Organization Certification Requirements.
If arguments are made to have these requirements specifically stipulated, then such argument can be extended to include every data and tool
that an operating entity (including RC, TOP and GOP) uses to perform all of its tasks. If that’s the case, there will be no end to the scope of
this extension as this may include such data as PMU data, RTU data, voltage, current, MW, Mvar, frequency, etc., and tools such as on-line
contingency analysis, EMS programs, line loading estimators, load flow programs, dynamic simulation software, etc. For years, operating
entities have been relying on these data and tools to perform their tasks, and there have not been any notable events that occurred due to
inaccurate data or tool capability.
We continue to disagree with the majority of the requirements in the standard that stipulate the capabilities that a BA must have in order to
perform its reliability tasks. In our view, these are more suited for inclusion in the Organization Certification Requirements as opposed to in
Reliability Standards. The ongoing process to ensure accuracy of operating information and tools is an essential component of any
operating entity which provides such services and registers with NERC as the responsible entity for complying with applicable Reliability
Standards. To have explicit requirements for having accuracy metering data at specific scan rate and availability (R1, R3 and R5), flagging
missing or invalid data (R4), having a process in place to detect and mitigate inaccurate or missing information (R6), and using common
source information between adjacent BAs (R7) are the fundamental organization requirements to enable a BA (and any operating entity)
performs its reliability tasks to meet its basic obligations.
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
Response
Dislikes
Likes
In R7.2, PJM’s concern here is that errors would be apparent in many more ways (and much more quickly) than by calculating hourly megawatt
values. This doesn’t appear to be a reliability requirement.
In R7, the word Tie-Line is not defined. In the NERC Glossary it is listed as “Tie Line.”
R7 requires the BAs to have a common source. This could possibly pose a conflict with CIP-005-5 R1, which could be interpreted to require a
Responsible Entity to have individual access to a meter.
PJM notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The same integrated
value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized” from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
0
0
0
0
0
0
Comment
Document Name
Answer
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
under certain conditions. We do not believe this is the intent of the requirement so it needs to be re-worded to not imply a continuous
accuracy requirement. If the intent is to use primary frequency metering equipment that has demonstrated or been tested to meet the 0.001
Hz accuracy requirement, then the requirement and/or the measure should be revised to clearly indicate this is the objective/intent.
0
0
0
R1. The Balancing Authority shall use a design scan rate not greater than six seconds in acquiring data necessary to calculate Reporting ACE.
䇲㼠㼕㼙㼑㻌㻻㼜㼑㼞㼍㼠㼕㼛㼚㼟㼉
[Violation Risk Factor: Medium] [Time Horizon: Real
Southern Suggests adding the below wording to R1 and M1:
The responsible entity that integrates resource plans ahead of time, maintains Demand and resource balance within a Balancing Authority Area, while
maintaining scheduled interchange and supporting Interconnection frequency in real time.
Southern suggests adding the below wording to the definition of Balancing Authority:
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
0
The proposed version of BAL-005 is inconsistent with the recommendations of the Independent Experts Review Project and the Results-Based
Reliability Standard Development Guidance.
R1, R3, and R7 are design parameters and should be moved to a Guideline (and reviewed as part of a BA Certification). They are not
performance-based, risk-based, or competency-based requirements.
R4 seems to overlap the proposed TOP-010-1 R2 creating a potentially double-jeopardy.”
Response
Dislikes
Likes
x
x
x
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. - 3
Response
Dislikes
Likes
2. The wording of R7.2 appears to be combining two requirements. The requirement to have a time-synchronized common source and to agree
upon the hourly megawatt-hour values the source provides. These should be separated out as the current verbiage is unclear.
1. Although it can be viewed as a “resource”, maintaining Interchange obligations is a unique enough task for a Balancing Authority to perform,
APS recommends leaving Interchange in as part of the Balancing Authority definition. “…maintains Demand and resource balance within a
Balancing Authority Area, while maintaining Interchange obligations, and supports Interconnection frequency in real time.”
0
0
The rationale states this is important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and NET
Interchange). If a BA can’t compute its own ACE then one of those three quantiles is unavailable. The RC does not rely on the BA for frequency. NET
tie flow is not used in any reliability studies (whereas individual tie flows would come from the TO) and NET Interchange is a market issue not a
reliability issue. Why then should the BA be mandated to tell the RC that it can’t calculate ACE?
R2 addresses reporting the loss of ACE to an RC.
This requirement is not a reliability based standard and is not needed.
REQUIREMENT 2
Also, if this standard is to remain then the name of the standard should be changed. It is now referred to as Balancing Area Control but the
requirements are for ACE Process Design. BA Control is addressed by BAAL requirements not by this standard.
The new R1 is a design requirement and not something that is subject to change
REQUIREMENT 1
The SRC proposes that BAL-005 be translated into a certification requirement for the following reasons:
ERCOT supports the comments of the IRC SRC. The comments are provided below:
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Response
Dislikes
Likes
M1. Each Balancing Authority will have dated documentation demonstrating that the data necessary to calculate Reporting ACE was designed to be
scanned at a rate not greater than six seconds. Acceptable evidence may include historical data, dated archive files; or data from other databases,
spreadsheets, or displays that demonstrate compliance.
Requirement 5 like Requirement 3.1 mandates an average availability. The concern that should be raised is that of mandating an average availability
value. If a BA has 100% availability it can stop calculating ACE for the entire last day of the year and still be compliant! Average availability is a make
work requirement. Every lost scan must be saved and summed over a year. If one were inclined to want an availability mandate then why not tie it into
the same time frame as the loss of ACE mandate?
REQUIREMENT 5
Requirement 4 is a fill-in-the-blanks standard unless the SDT defines what constitutes “invalid data” and defines “quality” (if the BA is to flag quality then
the term should be defined somewhere)
REQUIREMENT 4
If an availability mandate is needed, then why not tie it into the same time frame as the loss of ACE mandate?
Average availability (R3.1) on the other hand creates a realibilty gap, and that as written is a make work requirement. Every lost scan must be saved
and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making maintenance decisions, but as a
standard use of average availability could be seen as establishing a reliability gap since some could even say this is not a good use of computer time!
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable requirement? The SRC would
suggest that frequency meter accuracy is better left to a certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good idea that when a BA control center is not functional that it tells the RC but isn’t that fact covered elsewhere, such as IRO-005-3.1a R1.6
mandating that the RC monitor “Current ACE for all its Balancing Authorities.”?
0
0
Each BA shall support Interconnection frequency through monitoring Reporting ACE
0
Response
Dislikes
Likes
0
R2.
A Balancing Authority shall maintain adequate metering, communications, and control equipment to prevent becoming a Burden on the
Interconnection or other Balancing Authority Areas.
R1.
We suggest the Standard be completely revisited to be:
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Response
Dislikes
Likes
The SRC notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The same
integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized” from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
On the other hand, it is possible to have a process to handle no ACE values.
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process” Is it more important to
have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable requirement? The SRC would
suggest that frequency meter accuracy is better left to a certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good idea that when a BA control center is not functional that it tells the RC but isn’t that fact covered elsewhere, such as IRO-005-3.1a R1.6
mandating that the RC monitor “Current ACE for all its Balancing Authorities.”?
The rationale states this is important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and NET
Interchange). If a BA can’t compute its own ACE then one of those three quantiles is unavailable. The RC does not rely on the BA for frequency. NET
tie flow is not used in any reliability studies (whereas individual tie flows would come from the TO) and NET Interchange is a market issue not a
reliability issue. Why then should the BA be mandated to tell the RC that it can’t calculate ACE?
R2 addresses reporting the loss of ACE to an RC.
This requirement is not a reliability based standard and is not needed.
REQUIREMENT 2
Also, if this standard is to remain then the name of the standard should be changed. It is now referred to as Balancing Area Control but the
requirements are for ACE Process Design. BA Control is addressed by BAAL requirements not by this standard.
The new R1 is a design requirement and not something that is subject to change
REQUIREMENT 1
The SRC proposes that BAL-005 be translated into a certification requirement for the following reasons:
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Dislikes
Likes
0
0
The SRC notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The same
integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized” from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
On the other hand, it is possible to have a process to handle no ACE values.
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process” Is it more important to
have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
Requirement 5 like Requirement 3.1 mandates an average availability. The concern that should be raised is that of mandating an average availability
value. If a BA has 100% availability it can stop calculating ACE for the entire last day of the year and still be compliant! Average availability is a make
work requirement. Every lost scan must be saved and summed over a year. If one were inclined to want an availability mandate then why not tie it into
the same time frame as the loss of ACE mandate?
REQUIREMENT 5
Requirement 4 is a fill-in-the-blanks standard unless the SDT defines what constitutes “invalid data” and defines “quality” (if the BA is to flag quality then
the term should be defined somewhere)
REQUIREMENT 4
If an availability mandate is needed, then why not tie it into the same time frame as the loss of ACE mandate?
Average availability (R3.1) on the other hand creates a realibilty gap, and that as written is a make work requirement. Every lost scan must be saved
and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making maintenance decisions, but as a
standard use of average availability could be seen as establishing a reliability gap since some could even say this is not a good use of computer time!
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R3 is vague and has the potential for inconsistent implementation as worded.
SRP appreciates the efforts of the SDT and provides the following comments regarding the changes to BAL-005-1:
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Response
Dislikes
Likes
R7.2 Not all tie lines have time-synchronized meters. The adjacent BAs just need to operate to common real time meters. The same integrated value
for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized” from the requirement.
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Response
Dislikes
Likes
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area is included
within its metered boundaries.”
R1 from BAL-005-0.2b should be retained in BAL-005-1 and re-written as follows:
Comment
Document Name
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
Response
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0
Dislikes
Likes
na
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Comment
0
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
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Provided in ACES Comments
Comment
Document Name
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
Response
Dislikes
0
R6 – SRP recommends rewording the standard to avoid creating the super tem “Balancing Authority Interconnection.
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R5 – SRP recommends providing clarification on how the 99.5% is to be calculated?
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R4 – SRP recommends reducing ambiguity by adjusting the requirement to state “System Operator”.
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It is unclear whether the 99.95% availability calculation is to be applied independently to each individual metering point, or whether it should be the
average availability of all metering equipment.
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Document Name
Answer
Teresa Czyz - Georgia Transmission Corporation - 1,3 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Jason Snodgrass - Georgia Transmission Corporation - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Response
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Response
Dislikes
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Comment
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Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Response
Dislikes
Likes
Comment
Document Name
Answer
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Response
Dislikes
Likes
Comment
Document Name
Answer
Shivaz Chopra - New York Power Authority - 6
Response
Dislikes
Likes
Comment
0
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0
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Comment
Document Name
Answer
Jonathan Appelbaum - United Illuminating Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Anthony Jablonski - ReliabilityFirst - 10
Response
Dislikes
Likes
Comment
Document Name
Answer
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Laura Nelson - IDACORP - Idaho Power Company - 1
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Response
Dislikes
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Comment
0
Document Name
Answer
Glenn Pressler - CPS Energy - 1,3,5
Response
Dislikes
Likes
Comment
Document Name
Answer
Chris Scanlon - Exelon - 1, Group Name Exelon Utilities
Response
Dislikes
Likes
Comment
Document Name
Answer
Douglas Webb - Douglas Webb
Response
Dislikes
Likes
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0
0
0
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0
Comment
Document Name
Answer
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Response
Dislikes
Likes
Comment
Document Name
Answer
Tammy Porter - Tammy Porter
Response
Dislikes
Likes
Comment
Document Name
Answer
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeremy Voll - Basin Electric Power Cooperative - 3
0
0
0
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0
Response
Dislikes
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Comment
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Document Name
Answer
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
Louis Slade - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Response
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Response
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0
The SRC supports the retirement of BAL-006-2.
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Response
Dislikes
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SRP is in support of retiring BAL-006-2
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
3. If you are not in support of the retirement of BAL-006-2 and the development of a guideline, please provide your objection(s) and proposed
solution(s) in the area below.
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Response
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Duke Energy supports the retirement of BAL-006-2 in conjunction with the changes in BAL-005 as well as the development of the Guideline document
as an integrated package. We feel that implementation of just one of these suggestions, without the others, would not sufficiently maintain reliability
concerns with the grid.
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Response
Dislikes
Likes
Southern supports the retirement of BAL-006-2. However, we suggest requirements be included in a commercial alternative arrangement, such as a
NAESB standard, rather than a guideline that only suggests approaches and behaviors and is not binding or mandatory.
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Response
Dislikes
Likes
ERCOT joins the IRC SRC in supporting the retirement of BAL-006.
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
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Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Response
Dislikes
Likes
PJM supports the retirement of BAL-006.
Comment
Document Name
Answer
William Temple - William Temple
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
0
0
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Likes
0
Additionally, the BAL-005-1 Implementation Plan lacks clarity on effective dates for the Standards and definitions in question. BAL-001-2 is effective
July 1, 2016. There may not be an approval on definitions contained within BAL-005-1 before that time period. Additionally the SDT is unclear if the
definitions would apply to BAL-005-0.2b, which could still be in effect after BAL-001-2 is in effect but before BAL-005-1 becomes effective. A CEA will
have to evaluate the Standards and definitions that are FERC approved, not proposed, for compliance monitoring efforts.
In the BAL-005-1 Implementation Plan there is a reference to retirement of BAL-006-2 under “General Considerations” but further down there is a
reference to BAL-006-2 Requirement 3 under “Retirements”. Additionally, there is no reference to BAL-006-2 in the “Requested Retirement” section.
Which is correct?
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Response
Dislikes
Likes
: LG&E/KU would like to support the retirement of BAL-006 but as of now have questions regarding the guideline and implementation plan. For
example, in the transition to a guideline, must existing inadvertent balances be minimized or do existing balances simply disappear?
Comment
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Response
Dislikes
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We support the retirement of BAL-006-2.
Comment
Document Name
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BPA agrees that BAL
-2 is an energy accounting standard and not a Reliability Standard. However, guidelines are not enforceable. BPA agrees it
䇲㻜㻜㻢
is important to maintain requirements to calculate and account for Inadvertent Interchange. BPA proposes adding inadvertent accounting via a NAESB
standard or business practice since the NAESB WEQ Inadvertent Interchange Payback Standards already handles certain aspects of Interchange
accounting.
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Response
Dislikes
Likes
We agree with the SDT in proposing to retire BAL-006-2 and to develop an Inadvertent Interchange Guideline that will be approved by the NERC
Operating Committee at a later date.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Response
Dislikes
Likes
N/A
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Response
Dislikes
0
0
0
0
0
0
0
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Response
Dislikes
Likes
Comment
Document Name
Answer
Louis Slade - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Response
Dislikes
Likes
Comment
Document Name
Answer
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Response
Dislikes
0
0
0
0
0
0
Dislikes
Likes
0
Comment
0
Document Name
Answer
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Response
Dislikes
Likes
Comment
Document Name
Answer
Tammy Porter - Tammy Porter
Response
Dislikes
Likes
Comment
Document Name
0
0
0
0
0
0
Document Name
Answer
Chris Scanlon - Exelon - 1, Group Name Exelon Utilities
Response
Dislikes
Likes
Comment
Document Name
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
Response
Dislikes
Likes
Comment
Document Name
Answer
Glenn Pressler - CPS Energy - 1,3,5
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeremy Voll - Basin Electric Power Cooperative - 3
Response
0
0
0
0
0
0
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
Jonathan Appelbaum - United Illuminating Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Douglas Webb - Douglas Webb
Response
Dislikes
Likes
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Response
Dislikes
Likes
Comment
0
0
0
0
0
0
Comment
Document Name
Answer
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Response
Dislikes
Likes
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. - 3
Response
Dislikes
Likes
Comment
Document Name
Answer
Anthony Jablonski - ReliabilityFirst - 10
0
0
0
0
0
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0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Response
Dislikes
Likes
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
Laura Nelson - IDACORP - Idaho Power Company - 1
Response
Dislikes
Likes
0
0
0
0
0
0
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Teresa Czyz - Georgia Transmission Corporation - 1,3 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Shivaz Chopra - New York Power Authority - 6
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0
0
Response
Dislikes
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Comment
0
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Response
Dislikes
Likes
Comment
Document Name
Answer
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Response
Dislikes
Likes
Comment
Document Name
Answer
Jason Snodgrass - Georgia Transmission Corporation - 1
Response
Dislikes
Likes
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Its not that we aren’t in support of the modifications to FAC-001 however, we have a concern that the documentation mentioned in Rationale 3.3 and 4.3
(Functional Model) isn’t currently up to date. We would suggest to the drafting team to verify the latest review of this documentation. Also, we would
suggest the drafting team verifying that this document is properly aligned with other documentation such as: The Rules of Procedure (ROP), Glossary of
Terms and The Federal Power Act for consistency and reliability of the BES. Additionally, we would like for the drafting team to review the concept that
all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that pre-dates the NERC standards. It is a
concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly state that all facilities must be within
a BA in association referenced to BAL-005-0.2b Requirement R1 parts R1.1, R1.2 and R1.3. A FAC-001-3 requirement to have verification of this will
just lead to a paper exchange where TOPs, GOPs, and Loads will be asking BAs for pieces of documentation that they are within a given BA or to sign
agreements that acknowledge the facility is within a BA. Keep in mind this includes each and every load, every piece of transmission, and every
generator. This provides no reliability value.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Response
Dislikes
Likes
(4) We thank the SDT for the opportunity to comment on this standard.
(3) We recommend extending the implementation plan to 36 months. The proposed 12-month implementation plan is insufficient because
interconnection study requests can take as long as 18 months. These could take significant amounts of time if complex issues are encountered during
negotiations of interconnection agreements.
(2) However, we disagree with other proposed modifications in FAC-001-3. It was determined through the Paragraph 81 project that having Facilities
within a BA’s metered area boundaries are administrative and unnecessary. We suggest removing Requirement R3, part 3.3 and Requirement R4, part
4.3. These are administrative requirements that are not necessary for reliability. Furthermore, the NERC Rules of Procedure Section 501.4.4 already
requires NERC to “ensure that all Loads and generators are under the responsibility and control of one and only one Balancing Authority.” There are
equally efficient means that are already in effect; therefore, the SDT should remove these requirements, as they are unnecessary.
(1) We agree with the removal of the LSE function.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
4. If you are not in support of the proposed modifications to FAC-001-3, please provide your objection(s) and proposed solution(s) in the area
below.
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Additionally, GTC understands that FAC-001 and FAC-002 are complimentary Standards in a sense that FAC-001 requires Transmission Owners or
Generator Owners to define the interconnection requirements necessary to collect data from entities such that the Planning Coordinator and
Transmission Planners can study the impact of interconnecting new or materially modified Facilities to the BES in accordance with FAC-002.
FAC-001-2 was revised in 2013 to eliminate any requirements that were not necessary for reliability according to FERC paragraph 81 directions. As a
member of the FAC-001-2 SDT charged with this task, GTC along with the other members followed the directives of FERC and retained only the
requirements necessary for system reliability. As such 14 sub-requirements in FAC-001 were removed including a requirement for metering and
telecommunication.
Comment
Document Name
Answer
Jason Snodgrass - Georgia Transmission Corporation - 1
Response
Dislikes
Likes
As currently written in Draft 2, R3, part 3.3, appears to focus on “transmission Facilities” and ignores generation Facility and end-user Facility
connections. Similarly, R4, part 4.3, appears to focus on “generation Facilities” and ignores transmission Facility and end-user Facility connections.
R4, part 4.3: Procedures for confirming that the party seeking a new or materially modified interconnection has made appropriate provisions with a
Balancing Authority to operate within that Balancing Authority Area’s metered boundary.
R3, part 3.3: Procedures for confirming that the party seeking a new or materially modified interconnection has made appropriate provisions with a
Balancing Authority to operate within that Balancing Authority Area’s metered boundary.
While TVA supports the intent of addressing the metered boundaries of the Balancing Authority Area in FAC-001-3, we believe the language of R3, part
3.3, and R4, part 4.3, needs to be improved. We recommend that wording similar to that used in the rationale statements be used in the requirement
sub-parts as follows:
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Response
Dislikes
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While the latest proposed revisions to FAC-001-3 are an improvement (by removing the unnecessary R5, R6 and R7), the additions of R3.3 and R4.3
could be better worded, are unnecessary as requirements (they attempt to address an energy accounting problem, not a reliability problem), and likely
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
Response
Dislikes
Likes
It is GTC’s desire that the drafting team utilizes the justification provided by GTC to not move forward with the proposed R3.3 and R3.4 and a refer to
TOP-003-3 to demonstrate that there is currently not a reliability gap and also take the time to clarify the purpose statement to resolve the ambiguity
introduced with this revision which should not prevent the drafting teams goal of an approved ballot.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator Owners must
document and make Facility interconnection study requirements available so that entities seeking to interconnect will provide the information necessary
for studies conducted in accordance with FAC-002-2.
Therefore, GTC respectfully requests this drafting team to remove R3.3 and R4.3 as a proposed change to FAC-001-2 and further clarify the purpose
statement of FAC-001 to resolve the ambiguity that this current draft introduced by clarifying the purpose of FAC-001 which should align with FAC-002
by inserting the term “study” within the purpose statement such as:
In summary, GTC believes that the proposed requirements FAC-001-3-R3.3 and FAC-001-3-R4.3 address specific needs for operating the system and
therefore belong in an Operations Standard which is already being covered in requirements of FERC approved TOP-003-3 which describes the
information that TOs and GOs are required to provide to the Balancing Authority as specified by the Balancing Authority.
Based on the Ballot supporting material, the proposed FAC-001 R3.3 and R3.4 requirements were originally included in BAL-005-1. The goal of the
requirement in BAL-005-1 was to ensure that Area Control Error is calculated properly. Although GTC sees a merit in ensuring that the Area Control
Error is calculated properly, GTC believes that the proposed requirements (FAC-001-3-R3.3, R4.3) would violate paragraph 81 criteria and introduces
ambiguity associated with the aforementioned planning horizon vs operations horizon concerns that is currently not addressed in FAC-001 or FAC-002.
GTC believes this concern is already covered in operation horizon standards such as TOP-003-3. Specifically, R4 of TOP-003-3 already addresses and
requires the BA to distribute its data specification to entities that have data required by the BA analysis functions and Real-time monitoring. Additionally,
R5 of TOP-003-3 requires each TOP, GO, GOP, TO, LSE, and DP to satisfy the obligations of the documented specifications.
All of the requirements of FAC-001 are limited to the long-term planning time horizon. Based on the rationale and proposed language provided for R3.3
and R4.3, a new level of ambiguity has presented itself that could lead some to conclude that these interconnection requirements should be expanded
beyond the planning horizon and lead up to “commissioning of a Facility” which resides in the operations horizon.
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In summary, GTC believes that the proposed requirements FAC-001-3-R3.3 and FAC-001-3-R4.3 address specific needs for operating the system and
therefore belong in an Operations Standard which is already being covered in requirements of FERC approved TOP-003-3 which describes the
information that TOs and GOs are required to provide to the Balancing Authority as specified by the Balancing Authority.
Based on the Ballot supporting material, the proposed FAC-001 R3.3 and R3.4 requirements were originally included in BAL-005-1. The goal of the
requirement in BAL-005-1 was to ensure that Area Control Error is calculated properly. Although GTC sees a merit in ensuring that the Area Control
Error is calculated properly, GTC believes that the proposed requirements (FAC-001-3-R3.3, R4.3) would violate paragraph 81 criteria and introduces
ambiguity associated with the aforementioned planning horizon vs operations horizon concerns that is currently not addressed in FAC-001 or FAC-002.
GTC believes this concern is already covered in operation horizon standards such as TOP-003-3 and IRO-010-2. Specifically, R4 of TOP-003-3
already addresses and requires the BA to distribute its data specification to entities that have data required by the BA analysis functions and Real-time
monitoring. Additionally, R5 of TOP-003-3 requires each TOP, GO, GOP, TO, LSE, and DP to satisfy the obligations of the documented specifications.
All of the requirements of FAC-001 are limited to the long-term planning time horizon. Based on the rationale and proposed language provided for R3.3
and R4.3, a new level of ambiguity has presented itself that could lead some to conclude that these interconnection requirements should be expanded
beyond the planning horizon and lead up to “commissioning of a Facility” which resides in the operations horizon.
Additionally, GTC understands that FAC-001 and FAC-002 are complimentary Standards in a sense that FAC-001 requires Transmission Owners or
Generator Owners to define the interconnection requirements necessary to collect data from entities such that the Planning Coordinator and
Transmission Planners can study the impact of interconnecting new or materially modified Facilities to the BES in accordance with FAC-002.
FAC-001-2 was revised in 2013 to eliminate any requirements that were not necessary for reliability according to FERC paragraph 81 directions. As a
member of the FAC-001-2 SDT charged with this task, GTC along with the other members followed the directives of FERC and retained only the
requirements necessary for system reliability. As such 14 sub-requirements in FAC-001 were removed including a requirement for metering and
telecommunication.
Comment
Document Name
Answer
Teresa Czyz - Georgia Transmission Corporation - 1,3 - SERC
Response
Dislikes
Likes
The new R3.3 reads: “Procedures for confirming with those responsible for the reliability of affected systems of new or materially modified transmission
Facilities are within a Balancing Authority Area’s metered boundaries.” A simple fix might be to change the word “of” to “that” so that it reads
“Procedures for confirming with [someone] that new [things] are within a Balancing Authority Area’s metered boundaries.”.
If the SDT chooses to retain these requirements, some changes in the wording are warranted: R3.2 reads, “Procedures for notifying those responsible
for the reliability of affected system(s) of new or materially modified existing interconnections.” In order to understand the sentence, it is helpful to make
a substitution like the following: “Procedures for notifying [someone] of new [things].”
already included in most Facility Interconnection Requirements documents in the Metering and Telecommunications section under Guidelines and
Technical Basis (created in the new FAC-001-2), and/or in interconnection agreements between Facility owners and transmission providers.
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Requirement 3.3 and 4.3 should not be moved to FAC-001-3. The BA is in the best position to know its metered boundaries and confirm if any new or
modified transmission or generation project is within those metered boundaries. The proposed R3.3 and R4.3 should remain in BAL-005, but be
assigned to the BA. R1 from BAL-005-0.2b should be retained and re-written as follows:
We do not support the proposed changes to R3 and R4. The SDT, in the rationale boxes stated “It is the responsibility of the party interconnecting to
make appropriate arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries”. We do not believe it is
appropriate to shift the compliance responsibility of one entity to another and therefore suggests the SDT also include Distribution Provider in the
applicability section and then develop a requirement to read “Entity seeking to interconnect (TO, GO or DP) shall confirm with those responsible for the
reliability of affected systems that its newly installed or modified Facility is within a Balancing Authority Area’s metered boundaries”
The added requirements 3.3 and 4.3 are not clear. The drafting team copied R3.2 approach but it not work for 3.3. In R3.2 the Transmision Owner is
notifying the other reliability entities that new or modified interconnection is being pursued. Technically that would include a notice to the BA. But an
explicit sub-requirement is needed. Concerns with R3.3 are: 1. Use of word confirming. Confirming is beyond notification; a confirmation requires the
TO to maintain the response from the BA and possibly go further and verify the BA is truthful. The SDT reply to the last comments indicated it was really
concerned that the BA would not be aware of changes made by TO. 2. The use of phrase “those responsible for the reliability of affected systems” is not
needed and should be replaced with ‘responsible Balancing Authority’ since that is the only reliability function implicated by this subrequirement. 3.The
BA should be required to provide the procedure for notification from a TO when a new or modified interconnesction is being pursued. Then the TO can
align its Interconnection requirements document to the BA process.
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Response
Dislikes
Likes
It is GTC’s desire that the drafting team utilizes the justification provided by GTC to not move forward with the proposed R3.3 and R3.4 and a refer to
TOP-003-3 to demonstrate that there is currently not a reliability gap and also take the time to clarify the purpose statement to resolve the ambiguity
introduced with this revision which should not prevent the drafting teams goal of an approved ballot.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator Owners must
document and make Facility interconnection study requirements available so that entities seeking to interconnect will provide the information necessary
for studies conducted in accordance with FAC-002-2.
Therefore, GTC respectfully requests this drafting team to remove R3.3 and R4.3 as a proposed change to FAC-001-2 and further clarify the purpose
statement of FAC-001 to resolve the ambiguity that this current draft introduced by clarifying the purpose of FAC-001 which should align with FAC-002
by inserting the term “study” within the purpose statement such as:
0
0
0
0
Comment
Document Name
Answer
Shivaz Chopra - New York Power Authority - 6
Response
Dislikes
Likes
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that pre-dates the NERC
standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly state that all
facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper exchange where TOPs, GOPs, and Loads
will be asking BAs for pieces of documentation that they are within a given BA or to sign agreements that acknowledge the facility is within a BA. Keep
in mind this includes each and every load, every piece of transmission, and every generator. This provides no reliability value.
Every facility owner is required to register with NERC. PJM proposes that as part of that process, the facility owners identify the RC area, BA area and
TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas change, then the owner
must inform NERC of the change and also inform the entity(ies) that are involved.
PJM views FAC-001 as a reporting requirement that must be carefully drafted. The requirement must be crafted as an obligation that an owner incurs
“when circumstances change.” The obligation may be better addressed in a venue other than the reliability standards. One possibility would be to
include the essence of the requirement as part of the NERC registration process to avoid unnecessary compliance tracking.
Comment
Document Name
Answer
William Temple - William Temple
Response
Dislikes
Likes
Alternatively the proposed R3.3 and R4.3 could be moved to FAC-002-2. FAC-002-2 is more
appropriate than FAC-001-2 for this requirement
because FAC-002-2 applies to TOs and GOs “seeking to interconnect” new or modified facilities. Therefore FAC-002-2 is more in line with the SDT’s
rationale that “It is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities
are within the BA’s metered boundaries…”
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area is included
within its metered boundaries.”
0
0
0
0
0
0
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
4.3 In regions with multiple Balancing Authorities, Procedures for confirming with those responsible for the reliability of affected systems of new or
materially modified generation Facilities are within a Balancing Authority Area’s metered boundaries.
Recommend the standard language additions:
3.3 In regions with multiple Balancing Authorities, procedures for confirming with those responsible for the reliability of affected systems of new or
materially modified transmission Facilities are within a Balancing Authority Area’s metered boundaries.
The SDT should consider the impact of new requirements R3.3 and R4.3 in regions where a single BA exists. These requirements would not seem to
apply in cases such as ERCOT, where clearly any TO or GO facility additions are within the one and only BA’s metered boundaries.
Comment
Document Name
Answer
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Response
Dislikes
Likes
FAC-001-3. NYPA has a concern that R3.3 and 4.3 should be the responsibility of the interconnecting entity to ensure their facility is within a
BA’s metered boundary.
0
0
0
0
Comment
Document Name
Answer
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Response
Dislikes
Likes
Also, Duke Energy suggests a minor modification to language used in the sub-requirements of R3 and R4. We suggest the use of the term Procedure[s]
with the [s] accompanying. This clears up ambiguity that could arise in the event that an entity only has one procedure that is applicable to these
requirements.
We feel that these modifications and the resulting modifications to the Guidelines and Technical Basis section of the standard, better illustrates the
intent of the drafting team, without needing the requirements’ rationale to decipher said intent.
R4.3: Procedures for confirming that new or materially modified generation Facilities are accurately telemetered, modeled, and accounted in Real-time
systems of the Balancing Authority(s) designated by the interconnecting entity.
R3.3: Procedures for confirming that new or materially modified transmission Facilities are accurately telemetered, modeled, and accounted in Realtime systems of the Balancing Authority(s) designated by the interconnecting entity.
Duke Energy is not certain that the current language in R3.3 and R4.3 of the proposed FAC-001-3 adequately establishes that it is the responsibility of
the interconnecting entity to make the necessary arrangements, and that the Transmission Owner is responsible for confirming with a Generator, who
their Balancing Authority will be. We feel that this intent is clear from reading the Rationale for R3, but do not feel that this intent is ascertainable by
reading R3.3 on its own. Duke Energy suggests the following revisions to R3.3 and R4.3 to add clarity:
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Response
Dislikes
Likes
na
Comment
Document Name
Answer
0
0
Part 3.3 uses the term “materially modified”. RF believes this term is ambiguous and requests the SDT further clarify what is
considered a “materially modified transmission Facility”.
0
0
Part 4.3 uses the term “materially modified”. RF believes this term is ambiguous and requests the SDT further clarify what is
considered a “materially modified generation Facility”.
Comment
Document Name
Answer
Jonathan Appelbaum - United Illuminating Co. - 1
Response
Dislikes
Likes
i.
2. Requirement 4, Part 4.3
i.
1. Requirement 3, Part 3.3
ReliabilityFirst agrees the draft FAC-001-3 draft standard but offers the following comments for consideration.
Comment
Document Name
Answer
Anthony Jablonski - ReliabilityFirst - 10
Response
Dislikes
Likes
R4.3 – Procedures for confirming with the associated Balancing Authority that the new or materially modified generation and/or transmission
Facilities, that those generation and/or transmission Facilities are within its metered boundaries.
R3.3 – Procedures for confirming with the associated Balancing Authority that the new or materially modified generation and/or transmission
Facilities, that those generation and/or transmission Facilities are within its metered boundaries.
APS agrees with the approach for Requirements R3.3 and R4.3, in that it is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority, and that the Transmission Owner or Generation Owner is responsible for confirming that the party
interconnecting to make appropriate arrangements with a Balancing Authority. Since Transmission Owners and Generation Owners may receive either
transmission or generation interconnection requests, APS recommends revising the requirements as follows:
0
0
The difficulty with R3.3, as proposed, is evident when compliance scenarios are considered. For example, the Transmission Owner creates the required procedure
under R3.3. The rationale—the compliance goal—for R3.3 centers on a duty by of the party interconnecting (PI) to make appropriate arrangements with the BA to
R3.3 creates a compliance obligation for a disinterested party. The proposed R3.3, in effect, requires the Transmission Owner to create a procedure to promote the
exchange of information between a third party Facility interconnecting with a Generator Owner whose facility is used to connect to the Transmission system. The
procedure developed by the Transmission Owner must identify "affected systems," confirm who is responsible for reliability of the "affected systems," and, confirm
with the "affected systems" owner that new interconnected facilities are within the metered boundaries of the identified Balancing Authority.
Requirement 3.3
KCP&L does not support the proposed revisions to FAC-001-3 R3.3 and recommends not adopting the Requirement. The proposed revised Standard is
applicable to KCP&L as a registered Transmission Owner and, potentially, as a registered Generator Owner.
Comment
Document Name
Answer
Douglas Webb - Douglas Webb
Response
Dislikes
Likes
4. If proposed R3.3 was to be approved then it is missing the word "that". It should state: "Procedures for confirming with those responsible for the
reliability of affected systems that new or materially modified transmission Facilities are within a Balancing Authority Area’s metered boundaries.."
"R3.2 requires the TO to establish a procedure to notify those responsible for the reliability of affected system(s) of new or materially modified existing
interconnections. Notification means that the TO, requires either itself or the interconnecting party to contact the relevant reliability authorities and
provide notice of the facility. R3.3 requires the TO to establish a procedure to confirm that a facility is within a metered boundary of a BA. Confirmation
means that the TO, requires either itself or the interconnecting party to contact the BA and receive a letter of confirmation that the facility is in the BA
metered boundary. The requirement and measure for R3 is only that the processes are established in the requirements document. The requirements
document may reference a market or tariff as its process."
This is my proposed addition to Techincal Guideline section to address my comments 1 to 3:
3. What is the purpose of R3.3 requiring a confrimation with " those responsible for the reliability of affected systems" instead of just stating the
Balancing Authority. It should be the BA..
2. Do requirements R3.2 and R3.3 means the TO must perform this confirmation or can the procedure require the interconnecting party perform the
confirmation? UI believes the TO establishes the procedure, or writes into its interconnection document the BA's process, but the requirements
document can require the interconnecting party to perform the notifiction and confirmation. If so, this should be added to the Technical Guideline
section of Standard.
1. R3.2 has the TO establishing a procedure to provide a notification whle R3.3 requires a confirmation. What is the difference in actions between
notification and confirmation? Who or what is to be confirmed? The technical and guideline section should explain what the confirmation is supposed to
be.
0
0
Every facility own should be required to register with NERC. The SRC proposes that as part of that process the owners identify the RC area, BA area
and TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas change, then the
owner must inform NERC of the change and also inform the entitiy(ies) that will be changed.
The SRC views FAC-001 as a reporting requirement that must be carfully drafted. The requirement must be crafted as an obligation that an owner
incurs “when circumstances change”. The obligation may be better addressed in a venue other than the reliability standards. One possibility would be to
include the essence of the requirmentas part of the NERC registration process to avoid unnecessary compliance tracking.
ERCOT supports the comments of the IRC SRC. The comments are provided below:
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Response
Dislikes
Likes
Generally, defined terms better serve compliance with Standards and implementation of Requirements. The term, "affected system" is not defined. FERC approved
pro forma interconnection agreements define the term as, "…an electric system other than the Transmission Provider's Transmission System that may be affected by
the proposed interconnection." KCP&L believes there may be benefit aligning the undefined NERC Standard terms relating to interconnection facilities with
equivalent FERC pro forma interconnection agreements defined terms. While such an effort would require substantial effort to address all affected Standards, for the
purposes of this Standard, we would encourage adopting FERC’s pro forma definition for the proposed revision to FAC-001-3.
"Affected System"
R3.3: "Procedures for confirming with those responsible for the reliability of affected systems of new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries."
KCP&L recommends removing R3.3 or, in the alternative, suggests deleting "with those responsible for the reliability of affected systems of" from the proposed R3.3.
To achieve the stated rationale’s goal, It would seem the compliance duty should fall to the party interconnecting. Absent that, the Balancing Authority and/or the
Generator Owner whose facilities are used to interconnect to the transmission system would be in a better position to address Balancing Authority Area’s metered
boundaries. Also, the Requirement seems redundant since there are active NERC Standards requiring Generator Owners to inform Transmission Owners of changes
to the GOs’ facilities and Transmission Owners informing BA of new interconnections. Finally, from a practical viewpoint, it is just not likely a PI would connect
without metering and SCADA connections—all such activity providing visibility to the BA and TO of changes to the system.
ensure the PI Facilities are within the BA’s metered boundaries. If the PI fails to fulfill its duty, it raises the question: Where is the noncompliance under R3.3? The
Transmission Owner created the procedure, as required, yet, the stated rationale, goal, is not accomplished.
0
0
0
0
3.3. Procedures for confirming with responsible entities that that the new or modified Facilities are within a Balancing Authority Area’s metered
boundaries.
3.2. Procedures for notifying responsible entities of affected systems identified in part 3.1.
3.1. Procedures for coordinated studies of new or materially modified interconnections and impacts on affected system(s).
R3. Each Transmission Owner shall address the following items in its Facility interconnection requirements for new or materially modified existing
interconnections:
Exelon thinks R3 (and R4) needs to be re-written. We suggest:
Comment
Document Name
Answer
Chris Scanlon - Exelon - 1, Group Name Exelon Utilities
Response
Dislikes
Likes
This standard should not be a reliability standard, the contents of the standard do nothing to improve the reliability of the system.
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Response
Dislikes
Likes
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that pre-dates the NERC
standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly state that all
facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper exchange where TOPs, GOPs, and Loads
will be asking BAs for pieces of documentation that they are within a given BA or to sign agreements that acknowledge the facility is within a BA. Keep
in mind this includes each and every load, every piece of transmission, and every generator. This provides no reliability value.
0
0
0
0
Comment
Document Name
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
Response
Dislikes
Likes
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that pre-dates the NERC
standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly state that all
facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper exchange where TOPs, GOPs, and Loads
will be asking BAs for pieces of documentation that they are within a given BA or to sign agreements that acknowledge the facility is within a BA. Keep
in mind this includes each and every load, every piece of transmission, and every generator. This provides no reliability value.
Every facility own should be required to register with NERC. The SRC proposes that as part of that process the owners identify the RC area, BA area
and TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas change, then the
owner must inform NERC of the change and also inform the entitiy(ies) that will be changed.
The SRC views FAC-001 as a reporting requirement that must be carfully drafted. The requirement must be crafted as an obligation that an owner
incurs “when circumstances change”. The obligation may be better addressed in a venue other than the reliability standards. One possibility would be to
include the essence of the requirmentas part of the NERC registration process to avoid unnecessary compliance tracking.
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Response
Dislikes
Likes
We also note that the phrase "materilaly modifed" may be subject to interpretation during an audit. The Guideline and Technical Basis section allows the
use of engineering judgement when determing what is "material". It seems to beg the question, if an entity is using it's interconnection process and
associated procedures as required by the Standrd, the change is material. Has the SDT considerd removing material from the language? This phrase
is not defined or used in any other standard other than FAC-001 and 002. We believe either of these changes are non-substantive and would not
require an additional comment period.
0
0
0
0
Dislikes
Likes
0
0
R3.3 and R4.3: The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that predates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly
state that all facilities must be within a BA. The FAC-001-2 requirement to have verification of this will just lead to a paper exchange where TO, GO, will
be asking BAs for pieces of documentation that they are within a given BA or to sign agreements that acknowledge the facility is within a BA. This
provides no incremental reliability value. Recommend to remove this Requirement.
Comment
Document Name
Answer
Jeremy Voll - Basin Electric Power Cooperative - 3
Response
Dislikes
Likes
this needs work & here my support for the overall theme of comments submitted by MRO-NSRF, SCR, and also Oncor.
Comment
Document Name
Answer
Glenn Pressler - CPS Energy - 1,3,5
Response
Dislikes
Likes
Alternatively the proposed R3.3 and R4.3 could be moved to FAC-002-2. FAC-002-2 is more appropriate than FAC-001-2 for this requirement because
FAC-002-2 applies to TOs and GOs “seeking to interconnect” new or modified facilities. Therefore FAC-002-2 is more in line with the SDT’s rationale
that “It is the responsibility of the party interconnecting to make appropriate arrangements with a Balancing Authority to ensure its Facilities are within
the BA’s metered boundaries…”
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area is included
within its metered boundaries.”
Requirement 3.3 and 4.3 should not be moved to FAC-001-3. The BA is in the best position to know its metered boundaries and confirm if any new or
modified transmission or generation project is within those metered boundaries. The proposed R3.3 and R4.3 should remain in BAL-005, but be
assigned to the BA. R1 from BAL-005-0.2b should be retained and re-written as follows:
0
0
0
0
Oncor does not support the proposed changes to R3. The SDT, in the rationale box states “the Transmission Owner is responsibile for confirming that
the party interconnecting has made appropriate provisions with a Balancing Authority to operate within its metered boundaries”. Oncor does not believe
that the Transmission Owner should be responsible for the compliance of the interconnecting Transmission Owner. Therefore, Oncor recommends
Comment
Document Name
Answer
Tammy Porter - Tammy Porter
Response
Dislikes
Likes
SRP is in support of the proposed FAC-001-3
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Response
Dislikes
Likes
R3.3 and R4.3 The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that predates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary to explicitly
state that all facilities must be within a BA. The FAC-001-2 requirement to have verification of this will just lead to a paper exchange where TO, GO, will
be asking BAs for pieces of documentation that they are within a given BA or to sign agreements that acknowledge the facility is within a BA. This
provides no incremental reliability value. Recommend to remove this Requirement.
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Response
0
0
0
0
0
0
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Response
Dislikes
Likes
Dominion does not support the proposed changes to R3 and R4. The SDT, in the rationale boxes stated “It is the responsibility of the party
interconnecting to make appropriate arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries”. Dominion
does not believe it is appropriate to shift the compliance responsibility of one entity to another and therefore suggests the SDT also include Distribution
Provider in the applicability section and then develop a requirement to read “Entity seeking to interconnect (TO, GO or DP) shall confirm with those
responsible for the reliability of affected systems that its newly installed or modified Facility is within a Balancing Authority Area’s metered
boundaries”
Comment
Document Name
Answer
Louis Slade - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Response
Dislikes
Likes
Provided in ACES Comments
Comment
Document Name
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
Response
Dislikes
Likes
changing R3.3 to the following: "3.3. Requirement that new or materially modified transmission Facilities of the interconnecting Transmission Owner are
within a Balancing Authority Area's metered boundaries."
0
0
0
0
0
0
Dislikes
Likes
0
Comment
0
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Response
Dislikes
Likes
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Response
Dislikes
Likes
na
Comment
0
0
0
0
0
0
Document Name
Answer
Laura Nelson - IDACORP - Idaho Power Company - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Response
0
0
0
0
0
0
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Response
Dislikes
Likes
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. - 3
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Response
Dislikes
Likes
Comment
0
0
0
0
0
Response
Dislikes
Likes
Comment
0
Document Name
Answer
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Response
Dislikes
Likes
Comment
Document Name
Answer
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
11/10/2015
1/11/2016
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1 IN 1 ST
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-006-2 IN 1 ST
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 IN 1 ST
Comment Period Start Date:
Comment Period End Date:
Associated Ballots:
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, you can contact the Director of Standards, Howard Gugel (via email) or at (404) 446-9693.
All comments submitted can be reviewed in their original format on the project page.
There were 43 responses, including comments from approximately 117 different people from approximately 84 companies representing 8
of the 10 Industry Segments as shown in the table on the following pages.
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls | BAL-005-1, BAL-006-2 & FAC-001-3
Project Name:
Consideration of Comments
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
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
The Industry Segments are:
4. If you are not in support of the proposed modifications to FAC-001-3, please provide your objection(s) and proposed solution(s) in
the area below.
3. If you are not in support of the retirement of BAL-006-2 and the development of a guideline, please provide your objection(s) and
proposed solution(s) in the area below. JR
2. If you are not in support of the proposed modifications to BAL-005-1, please provide your objection(s) and proposed solution(s) in
the area below.
1. The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide
sufficient clarity? If not, please explain in the comment area below. JR
Questions
2
Name
2
Segment(s)
RFC
Region
ISO
Standards
Review
Committee
Group Name
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
PJM
2
Interconnection,
L.L.C.
Mark Holman
Kathleen
Goodman
Greg Campoli
Ali Miremadi
Terry Bilke
Liz Axson
TRE
RFC
WECC
NPCC
NPCC
RFC
NPCC
PJM
2
Interconnection,
L.L.C.
Ben Li
Group
Member
Region
SPP
Group
Member
Segment(s)
Charles Yeung PJM
2
Interconnection,
L.L.C.
Group
Group Member
Member Name Organization
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
PJM
Albert
Interconnection, DiCaprio
L.L.C.
Organization
Name
3
Chris
Scanlon
Colby
Bellville
Exelon
Duke Energy
5
1,3,5,6
1
6
Exelon
Utilities
ACES Power
Marketing
ACES Power
Marketing
Shari Heino
Kevin Lyons
LCRA
Compliance
5
6
Dale Goodwine Duke Energy
Greg Cecil
Lower Colorado 6
River Authority
Lower Colorado 1
River Authority
Lower Colorado 5
River Authority
Michael Shaw
Teresa
Cantwell
Dixie Wells
Duke Energy
3
1
3
1
1
1,5
1
4,5
1,3,5,6
TRE
TRE
TRE
RFC
SERC
FRCC
RFC
RFC
RFC
MRO
TRE
WECC
WECC
MRO
SPP
SERC
1,3
1
RFC
1
Duke Energy
Lee Schuster
Duke Energy
Exelon
ACES Power
Marketing
John Shaver
John Bee
ACES Power
Marketing
John Shaver
Exelon
ACES Power
Marketing
Michael
Brytowski
Chris Scanlon
ACES Power
Marketing
Ellen Watkins
ACES
Bob Solomon ACES Power
Standards
Marketing
Collaborators Ginger Mercier ACES Power
Marketing
FRCC,RFC,SERC Duke Energy Doug Hils
NA - Not
Applicable
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Lower Colorado Dixie Wells
River Authority
Brian Van
Gheem
ACES Power
Marketing
4
Kelly Dash
Kelly Dash
6
1,2,3,4,5,6
NPCC
MRO
Dominion
Con Edison
MRO-NERC
Standards
Review
Forum
(NSRF)
1
MRO
MRO
Chuck
Lawrence
Chuck
Wicklund
1,3,5,6
MRO
MRO
MRO
Kayleigh
Wilkerson
Jodi Jenson
Larry Heckert
2
Shannon
Weaver
1,5
MRO
MRO
Brad Perrett
Scott Nickels
3,4,5,6
Tom Breene
Kelly Dash
Randi Heise
NA - Not
Applicable
1,3,5,6
5,6
Dominion Dominion
Resources, Inc.
Edward Bedder Kelly Dash
Kelly Dash
1,3,5,6
Amy Casucelli
MRO
1,3,5
Tony Eddleman MRO
MRO
1,3,5,6
Terry Harbour MRO
4
1,3,5,6
Mike Brytowski MRO
MRO
1,3,5,6
Mahmood Safi MRO
4
1,6
1,3,5,6
Dave Rudolph MRO
1,3,5
3,4,5,6
Joe Depoorter MRO
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Louis Slade
Dominion Dominion
Resources, Inc.
Emily
Rousseau
MRO
NPCC
NPCC
NPCC
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
5
Marsha
Morgan
1,3,5,6
SERC
Southern
Company
SERC
SERC
Dominion 5
Dominion
Resources, Inc.
Dominion 1,3
Dominion
Resources, Inc.
1,3
Dominion Dominion
Resources, Inc.
1,3
Dominion Dominion
Resources, Inc.
Nancy
Ashberry
Larry Nash
Candace L
Marshall
Larry W
Bateman
SERC
1
Robert
Schaffeld
Southern
Company Southern
NPCC
5
Dominion Dominion
Resources, Inc.
Russell Deane
SERC
RFC
SERC
5
Jeffrey N Bailey Dominion Dominion
Resources, Inc.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Southern
Company Southern
SERC
Dominion 5
Dominion
Resources, Inc.
Chip
Humphrey
RFC
Dominion 5,6
Dominion
Resources, Inc.
Louis Slade
SERC
Dominion 1,3,5,6
Dominion
Resources, Inc.
Connie Lowe
6
Ruida Shu
1,2,3,4,5,6,7 NPCC
RSC no UI
O&R
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Guy Zito
Brian
Shanahan
Rob Vance
1
1
NA - Not
Applicable
1
5
William Shultz Southern
Company Southern
Company
Services, Inc.
Northeast
Power
Coordinating
Council
3
R Scott Moore Southern
Company Southern
Company
Services, Inc.
Paul
Malozewski
6
Company
Services, Inc.
Southern
Company Southern
Company
Services, Inc.
John Ciza
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Northeast
Power
Coordinating
Council
Company
Services, Inc.
NPCC
NPCC
NPCC
NPCC
SERC
SERC
SERC
7
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Randy
MacDonald
Wayne
Sipperly
David
Ramkalawan
Glen Smith
Brian O'Boyle
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
2
Northeast
Power
Coordinating
Council
Gregory A.
Campoli
5
4
4
4
2
1
Mark J. Kenny Northeast
Power
Coordinating
Council
Coordinating
Council
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
8
7
2
2
3
4
Alan Adamson Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Northeast
Power
Helen Lainis
Michael Jones Northeast
Power
Coordinating
Council
Northeast
Power
Coordinating
Council
Kathleen M.
Goodman
Silvia Parada
Mitchell
Connie Lowe
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
6
Bruce Metruck Northeast
Power
Coordinating
Council
4
5
Brian Robinson Northeast
Power
Coordinating
Council
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
NPCC
9
2
SPP
SPP
Standards
Review
Group
SPP
3,5
Southwest
Power Pool, Inc.
(RTO)
Jim Nail
SPP
NPCC
SPP
5
NPCC
Southwest
2
Power Pool, Inc.
(RTO)
Northeast
Power
Coordinating
Council
Brian O'Boyle
3
NPCC
Jason Smith
Northeast
Power
Coordinating
Council
Kelly Silver
2
NPCC
NPCC
Southwest
2
Power Pool, Inc.
(RTO)
Northeast
Power
Coordinating
Council
Si Truc Phan
1
1
Shannon
Mickens
Northeast
Power
Coordinating
Council
Sylvain
Clermont
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Southwest
Shannon
Power Pool, Inc. Mickens
(RTO)
Northeast
Power
Coordinating
Council
Michael Forte
Coordinating
Council
10
Southwest
1,3,5,6
Power Pool, Inc.
(RTO)
Kevin Giles
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Southwest
1,3,5
Power Pool, Inc.
(RTO)
Mike Kidwell
SPP
SPP
11
No
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Thank you for your comment. As written, the standard uses “Balancing Authority Area” and “Demand” as two separate defined terms.
The SDT does not intend for the terms to be combined into one term.
Thank you for your comment. The drafting team will work with NERC staff to request a change to the NERC Rules of Procedure to align
the definitions.
Response
Dislikes
Likes
SRP recommends removing or defining terms capitalized but not defined in the NERC Glossary of Terms such as Control Area and
Balancing Area. Capitalizing terms that are not defined creates confusion even when used in the rationale areas.
Primary Inadvertent Interchange is not a NERC defined term. It is a defined WECC term, SRP recommends adding Primary Inadvertent
Interchange to the terms used continent wide. as the revised ATEC definition will be effective continent wide.
The proposed definition of AGC combines defined terms to create the phrase “Balancing Authority Area Demand” ERC recommends
rephrasing the definition to avoid using one defined term to modify another. An alternative might be “Demand within a Balancing
Authority Area”.
Modifying the definition of Balancing Authority would misalign the term with the definition found in the NERC Rules of Procedure. SRP
recommends retaining the current definition of Balancing Authority.
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
1. The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide
sufficient clarity? If not, please explain in the comment area below.
12
No
0
0
No
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Automatic Generation Control (AGC): A process designed and used to automatically adjust a Balancing Authority Area’s Demand and
resources to help maintain the Reporting ACE of a Balancing Authority Area within the bounds required by applicable NERC Reliability
Standards.
Duke Energy suggests a modification to the proposed definition of Automatic Generation Control (AGC), which we feel would enhance
clarity and maintains the assumed intent of the drafting team. We recommend the following:
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Thank you for your comment. The drafting team is developing a guideline which should clarify expectations for Functional Entities.
Response
Dislikes
Likes
13
The definition of AGC is fine, but in the process of combining the need for common sources regarding MW and MWh values into the
proposed R7, the association between AGC, ACE, MW, and MWh quantities is less clear. The user now has to combine the definitions for
AGC, Reporting ACE, and R7 to get an equivalent picture compared to the original requirement. Maybe some references or revised
wording in R7 would help clarify the expectations.
Comment
Document Name
Answer
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Thank you for your comment. The drafting team will review the standard and eliminate any capitalized term not defined.
Thank you for your comment, Primary Inadvertent Interchange is defined in the proposed continent wide term “ATEC.”
0
0
No
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Dislikes
Likes
7.2. a time synchronized common source to determine hourly megawatt-hour values agreed-upon to aid in the identification and
mitigation of errors.
7.1. a common source to provide information to both Balancing Authorities for the scan rate values used in the calculation of Reporting
ACE; and,
14
7. Each Balancing Authority shall ensure that each Tie-Line, Pseudo-Tie, and Dynamic Schedule with an Adjacent Balancing Authority that
is included in the ACE equation is equipped with: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
HQT believes that Requirement 7 should apply specifically to tie lines, pseudo-ties and dynamic schedules that included in the ACE
equation. Even though having the same scan-rate measure and having a time synchronized common source is a good practice, Tie-lines
that are not included in the ACE equation that are not equipped with such will not affect adversely the control of a balancing
authority. HQT proposes to modify R7 as below:
Comment
Document Name
Answer
Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Thank you for your comments. The drafting team agrees with your clarification and has updated the definition accordingly. This revision
is not a substantive change, as the SDT has always intended for AGC to “automatically” adjust a Balancing Authority Area’s Demand and
resources to maintain Reporting ACE. This intent is reflected in the Rationale for AGC.
Response
Dislikes
Likes
We feel that the above definition adds clarity, and with the addition of the term automatically in the definition, more adequately
describes the function that AGC provides.
No
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
15
“Demand” is defined in the NERC Glossary as the rate at which energy is used by the customer. As written, the AGC definition could be
interpreted to mean a BA is required to utilize Demand controls to adjust ACE. A BA should not be expected to use Demand controls to
adjust ACE because the real-time nature of ACE and some current forms of Demand controls are not necessarily compatible. Additionally,
the SDT’s proposed definition does not mention Interchange which is a component of ACE and can be used to adjust ACE. Because
Interchange has not typically been understood to be included in the term “resources,” LG&E/KU recommend “Interchange” be expressly
Automatic Generation Control (AGC): A process designed and used to adjust a Balancing Authority Area’s Demand, Interchange, or
resources, as applicable, to help maintain the Reporting ACE of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
Comments: LG&E/KU recommend the AGC definition be modified to add flexibility as follows:
No X
Yes
The BARC 2.1 SDT has modified the definition of AGC and Pseudo Tie. Do you agree that the proposed modifications provide sufficient
clarity? If not, please explain in the comment area below.
These comments are submitted on behalf of Louisville Gas and Electric Company and Kentucky Utilities Company
(“LG&E/KU”) LG&E/KU are registered in the SERC region for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE,
PA, PSE, RP, TO, TOP, TP, and TSP.
Comment
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Thank you for your comments. The drafting team believes the requirement as drafted assures reliable operation at all times and does not
leave any doubt in the handling of information.
Response
0
0
No
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Dislikes
Likes
If the SDT does move forward with the proposed changes to the AGC definition, Texas RE recommends revising the proposed definition
slightly to correct what appears to be a typographical error. Specifically, Texas RE believes the phrase “that of” should be struck so that
the proposed AGC definition reads: “A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help
maintain the Reporting ACE in a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.”
16
Texas RE recommends that the SDT consider the impact of changing the definition of Automatic Generation Control (AGC) on other NERC
Glossary definitions prior to implementing such a change in this project. Although the SDT’s stated goal of converting the AGC definition
from a prescriptive “how to” requirement to an arguably more flexible, performance-based approach is laudable, Texas RE notes that
AGC is used in other NERC Glossary definitions and, as currently defined, represents a commonly understood term in the industry. For
example, the term AGC is used in the following defined terms: Anti-Aliasing Filter, Overlap Regulation Service, and proposed Remedial
Action Scheme. Accordingly, modifying the AGC definition in one context without considering the consequences of such a change for
other defined terms could introduce unnecessary uncertainty and confusion, as well as lead to unintended consequences. In light of the
interlocking usage of AGC, Texas RE recommends that the SDT either retain the existing AGC definition or, at a minimum, consider the
impact of changing the AGC definition as part of this project prior to making any changes.
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. – 10
Thank you for your comment. Please see the clarification change to the definition. There was never any intent in the original definition
that AGC was inclusive of Demand and resources. Also, Interchange is included in the defined term “Reporting ACE.”
Response
Dislikes
Likes
included in the definition of AGC. If the SDT does not accept the above recommendation, should it be the industry’s understanding that
the term “resources” includes Interchange?
No
0
0
0
0
No
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Response
Dislikes
Likes
Comment
Document Name
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
Thank you for your comment. The SDT agrees and has made minor modifications to the definition. Regarding your question about
"alternate control process", an alternate control process could mean manual control.
Response
Dislikes
Likes
Regarding the modified definition of Pseudo-Tie, BPA requests clarification of what constitutes an "alternate control process."
17
BPA disagrees with the modified definition of AGC; AGC is equipment or a system, not a process. Also, BPA suggests that the clause "...in
that of a BAA..." could be simplified to "in a BAA."
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 – WECC
Thank you for your comment. The SDT has made minor conforming modifications to the definition.
Response
Yes
0
0
Yes
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Dislikes
Likes
Please check and revise as appropriate.
“A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a
Balancing Authority within the bounds required by applicable NERC Reliability Standards.”
18
The phrase “..help maintain the Reporting ACE in that of a Balancing Authority Area …” in the revised definition reads a bit awkward. We
interpret the definition is meant to be:
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Thank you for your comment. The SDT has made minor conforming modifications to the definition.
Response
Dislikes
Likes
A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a
Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.
Southern suggests the below change to the definition of AGC:
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
0
0
Yes
Yes
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Thank you for your comment, the SDT does not believe a rationale box is necessary for the Pseudo Tie Definition.
Response
Dislikes
Likes
19
We would suggest to the drafting team to develop a rationale box for the modification of the Pseudo Tie definition as they did for the
AGC definition. We feel this would help provide clarity on why the drafting team made the modifications to this term’s definition and how
this change will have an impact on the reliability of the BES.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Response
Dislikes
Likes
N/A
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Thank you for your comment. The SDT has made minor conforming modifications to the definition.
Response
0
0
Yes
0
0
Yes
0
0
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Dislikes
Likes
Comment
Document Name
Answer
Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO
Response
Dislikes
Likes
Comment
Document Name
Answer
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Response
Dislikes
Likes
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
20
0
0
Yes
0
0
Yes
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Response
Dislikes
Likes
Comment
Document Name
Answer
Jeremy Voll - Basin Electric Power Cooperative - 3
Response
Dislikes
Likes
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Response
21
0
0
0
0
Yes
0
0
Yes
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Document Name
Answer
Douglas Webb - Douglas Webb
Response
Dislikes
Likes
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Response
Dislikes
Likes
22
0
0
0
0
Yes
0
0
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Response
Dislikes
Likes
Comment
Document Name
Answer
Laura Nelson - IDACORP - Idaho Power Company - 1
Response
Dislikes
Likes
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. - 3
Response
Dislikes
Likes
Comment
23
0
0
Yes
0
0
0
0
Yes
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Response
Dislikes
Likes
Comment
Document Name
Answer
William Temple - William Temple
Response
Dislikes
Likes
Comment
Document Name
Answer
Shivaz Chopra - New York Power Authority - 6
Response
Dislikes
Likes
Comment
Document Name
Answer
24
0
0
Yes
0
0
Yes
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
Response
Dislikes
Likes
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Response
Dislikes
Likes
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
25
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Thank you for your recommendation. The SDT has made minor conforming modifications to the definition.
Response
Dislikes
Likes
Please check and revise as appropriate.
“A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE of a
Balancing Authority within the bounds required by applicable NERC Reliability Standards.”
The phrase “..help maintain the Reporting ACE in that of a Balancing Authority Area …” in the revised definition reads a bit awkward.
We interpret the definition is meant to be:
26
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
R1: Thank you for your comment. The word “design” was added to the term scan rate to assure that when a BA’s EMS missed an
occasional scan of data that the BA would not be held to be non-compliant with the requirement.
Response
Dislikes
Likes
27
In R7.2, many dynamic schedules do not have MWH meters; the MWH value is simply the integrated scan rate data for the dynamic
schedule. BPA proposes 7.2 be modified to read:
7.2 for all Tie-Lines and metered Psuedo-Ties and metered Dynamic Schedules, a time-synchronized common source to determine hourly
megawatt-hour values agreed upon to aid in the identification and mitigation of errors.
In R7.1 BPA requests “information....for the scan rate values used in the calculation of Reporting ACE” be defined. BPA is unsure how to
address the dynamic schedule portion of this requirement.
R6: BPA still has concerns as to how R6 would be met. This requirement seems subjective and open-ended; it would be difficult for an
auditor to apply a consistent metric or method to validate compliance. BPA proposes the following: “Each Balancing Authority that is
within a multiple Balancing Authority Interconnection shall implement an Operating Process to ensure the accuracy of scan-rate data
used in the calculation of Reporting ACE for each Balancing Authority Area. The process must accomplish the following:
a. Compare MWh values from common source meters to integrated scan rate values
b. Xxx
c. Xxx
R1: BPA requests definition of “design scan rate” as identified in the R1. Scan rate is not a defined term in the NERC Glossary. It is
unclear to what the SDT means by design scan rate and why the word “design” was added in this second draft.
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
2. If you are not in support of the proposed modifications to BAL-005-1, please provide your objection(s) and proposed solution(s) in
the area below.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
(4) The SDT assumes that all tie lines between Balancing Authorities use time-synchronized meters. This may not always be true. We
recommend the removal of the term “time synchronized” in Requirement R7, Part 7.2 and allow Balancing Authorities to continue to
(3) We suggest that Requirement R5 be removed because there is an equally efficient and suitable manner of achieving the reliability
result through the NERC Event Analysis (EA) Process. The EA Process, category 1h, requires entities to report when there is a loss of
monitoring or control at a Control Center, and could include Reporting ACE calculation capabilities. Hence, this requirement would then
be unnecessary.
(2) The term “operator” in Requirement R4 is too broad and the SDT should replace it with “System Operator.” When we previously
identified this as a concern, the SDT’s response was that “By using the term operator, the BA will assure the information is provided to
the correct personnel.” Balancing Authorities are already required to identify such personnel as System Operators in PER-003-1 R3. The
SDT should use the System Operator glossary term to align with other reliability requirements and to avoid confusion.
28
(1) We continue to have concerns with Requirement R4 and the approach taken in the wording of this requirement. We agree with the
SDT that bad data quality will lead to an inaccurate ACE calculation. However, we feel the SDT should move away from concerns over
data quality and instead focus on Reporting ACE calculation capabilities, as it is used by System Operators as a primary metric in making
critical operating decisions.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
R7.1 & 7.2 Thank you for your comment. The STD intentionally left the word “meter” out of the requirement to allow BA’s to use other
common sources of data to support the correct calculation of ACE. The important part of the requirement is not where that data comes
from. The important part of the requirement is that each BA use scan rate data based on the same source having the same value. This
source could be a calculated schedule, a fixed value, or a common metering point. An integrated value is also acceptable for the
synchronized value as long as it is integrated from the same source so that errors can be identified when they occur.
R6. Thank you for your comment. An Operating Process that would meet the intent of R6. is described in Section VIII. - Special Conditions
and Calculations under the Title IME (Interchange Meter Error). The SDT decided the requirement should not define the specific process
because it may vary from BA to BA. Therefore, the process is defined in general terms rather than specifically.
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Response
Dislikes
Likes
We have a concern pertaining to Requirement R3 parts 3.1 and 3.2. Our group would suggest that the drafting team provide clarity on
what are the intents for this particular Requirement and its parts. At this particular time, we are interpreting that the frequency source
has to be within 1mHz accuracy for 99.95% of the year.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
29
(1) Thank you for your comment. The SDT is unclear with respect to your suggested change.
(2) Thank you for your comment. The SDT believes the term operator is appropriate to reflect the differences within BAs. In the
context used the term operator only applies to the BA operator, while the term System Operator includes the Transmission
Operator, Generation Operator and Reliability Coordinator.
(3) Thank you for your comment. The NERC Event Analysis Process (EA) only requires reporting of a loss of monitoring or control, it
does not include any requirement with respect to how often or how long a loss of monitoring or control is acceptable for
reliability.
(4) Thank you for your comment. If the meters used for determining MWh values are not time synchronized, then the Operating
Process required in R6 would not be valid. Time synchronization is intended to include all forms, such as accumulator freeze
pulses, and not to require a specific time synchronizing mechanism. The SDT believes that Requirement R7, as written, is binary in
nature. If a requirement is binary then it can only have one VSL, Severe.
Response
Dislikes
Likes
operate to a common source when conducting their end-of-hour checks with their Adjacent Balancing Authorities. We also recommend
the expansion of the VSLs for Requirement R7 where failure to meet one part would be High, and failure to meet both would be Severe.
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30
In reading Requirement R1 and M1, it is unclear whether or not there is a requirement to utilize a scan rate. R1 indicates “The Balancing
Authority shall use a design scan rate…” This almost looks like it should read “The Balancing Authority shall use a scan rate” OR “The
Balancing Authority shall design a scan rate”. Texas RE recommends there be a requirement to both design and utilize a scan rate as it
increases the integrity of data during events as indicated by the rationale.
Requirement R1: Scan Rate
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. – 10
Thank you for your comment. The SDT believes that the use of the term “scan-rate data” is more specific than the term “data” and
applies to the specific Operating Process required in R6.
Response
Dislikes
Likes
In R6 the SDT is using a new term called “scan rate data” which is not a defined term. This term is rather ambiguous. The
phrase “affecting the accuracy of data” is clear enough. Or possibly say the accuracy of data used in calculating ACE. In 7.1 the SDT uses
a term called “scan rate values”. The scan rate is how fast we collect the data, it is not the type of data used here. All SCADA data has a
scan rate, this could really be referring to almost anything.
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 -– SERC
Thank you for your comment. The SDT agrees with your interpretation of the requirement.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Texas RE recommends the standard language explicitly state how DC ties should be handled rather than indicating an exclusion. In the
SDT’s comment responses for Texas RE’s comments on the initial ballot, the SDT states “In the definition of Reporting ACE asynchronous
DC ties between Interconnections are excluded from Reporting ACE and are handled as either a generator or load” and “Reporting ACE
has been redefined to require that all DC asynchronous tie lines with other interconnections be represented as Source-Sink pairs and
excluded from Reporting ACE“ yet there is no written requirement for the DC ties to be handled in any way.
Reporting ACE
31
Texas RE noticed R6 does not address a single Balancing Authority Interconnection. Texas RE recommends there be a requirement for an
Operating Process to identify and mitigate errors affecting the accuracy of scan rate data used in calculating Reporting ACE even in single
Balancing Authority Interconnections.
Requirement R6: Singe Balancing Authority Interconnection
As previously submitted for the initial ballot, Texas RE recommends the SDT use the term “System Operator” in R4. The rational states
“System operators utilize Reporting ACE as a primary metric to determine operating actions or instructions. When data inputs into the
ACE calculations are incorrect, the operator should be made aware through visual display. When an operator questions the validity of the
data, actions are delayed and the probability of adverse events occurring can increase.” The definition of System Operator is “An
individual at a control center (Balancing Authority, Transmission Operator, Generator Operator, Reliability Coordinator) whose
responsibility it is to monitor and control that electric system in real time.” The response provide by the SDT to this issue was “The SDT
thanks you for your comment. However, the SDT believes that the term System Operator is too broad and may not address the correct
personnel. By using the term operator, the BA will assure the information is provided to the correct personnel.” A System Operator
needs to be aware of any data issues to make the correct decisions. A BA can provide the information to any other personnel it so desires
but the System Operator must, at a minimum, have access to the Reporting ACE information. As written, and interpreted by the SDT,
there could be possible gaps in providing the individuals whose responsibility it is to monitor and control that electric system in real time
correct information. There may not be consistency within Balancing Authorities as to who the “operator” is in this requirement. Texas RE
suggests the verbiage “System Operator and other personnel (as determined by the BA)” to provide clarity. As is, if a System Operator
does not have the information the Balancing Authority will be compliant but may hinder reliability by delaying actions and increasing the
probability of adverse events occurring. The non-definitive term “operator” will inherently inject non-uniformity in determining
compliance. Each entity will have a different interpretation of what “operator” means which will appear as an inconsistency in the
Regional Entity review. If an “operator” who is not a System Operator is making and acting on decisions that control the electric system
in real time, is that not a concern of the SDT?
Requirement R4: System Operator
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January 28, 2016
R1: Thank you for your comment. The word “design” was added to the term “scan rate” to assure that when a BA’s EMS missed an
occasional scan of data that the BA would not be held to be non-compliant with the requirement.
Response
Dislikes
Likes
The VSL for R4 should reflect System Operators.
Texas RE notes that some of the proposed changes to the Standard language have not been flowed through to all proposed VSLs. Texas
RE recommends that the SDT review this language and ensure that the final Standard language is accurately reflected in the
corresponding VSLs. For example, in the VSLs for R2 there were only corrections in the Lower VSL language to capture changes in the
Standard. The changes should be reflected in the other VSLs associated with R2.
VSL Language
The BAL-005-1 Implementation Plan lacks clarity on effective dates for the Standards and definitions in question. BAL-001-2 is effective
July 1, 2016. There may not be an approval on definitions contained within BAL-005-1 (effectively BAL-005-1 itself unless the SDT has
some other unapproved process in mind) before that time period. Additionally the SDT is unclear if the definitions would apply to BAL005-0.2b, which could still be in effect after BAL-001-2 is in effect but before BAL-005-1 becomes effective. A CEA will have to evaluate
the Standards and definitions that are FERC approved, not proposed, for compliance monitoring efforts.
Implementation Plan
32
Texas RE recommends changing the verbiage from “each calendar year” to “each rolling 12 month period”. Specifically, R3 and R5
include the term “calendar year” which implies Jan 1 to Dec 31. Therefore, if a CEA evaluates compliance to the Requirement in midyear, there cannot be an assertion of compliance for the current year. Consequently, if the CEA returns in two years, the half year’s
period of data should be available to ascertain compliance (per the Evidence Retention statements) but the BA may not provide the data
based on the RoP Appendix 4C Section 3.1.4.2). Texas RE considers this as a gap in compliance monitoring (and reflect a possible gap in
reliability). The SDT assertion that “Since an Audit Period will include at least one entire calendar year” is incorrect. A BA has to be
audited AT LEAST once every three years but may be audited more often as needed. As written the BA is non-compliant, per the VSLs,
until a calendar year is complete.
Calendar Year
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Requirement 3:
LG&E/KU have recommended a change to the proposed AGC definition and provided an explanation in the “comments” section for
question 1. Other comments regarding BAL-005-1 follow.
Comment
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
33
VSL Language: Thank you for your comment. The SDT has reviewed the language for Requirement R2 and made the appropriate changes.
The SDT has not modified the language to state System Operator instead of operator, therefore the VSL should not include the term
System Operator.
Implementation Plan: Thank you for your comment. The SDT intends to file the proposed modifications prior to July 1, 2016 in
compliance with the FERC directive. In addition, the proposed modification to the Reporting ACE definition incorporating thee ATEC term
has no impact on reliability since the WECC Regional Standard includes the ATEC definition.
Calendar Year: Thank you for your comment. The SDT has considered your comment at length. However, we believe such an
interpretation is too strict and would lead to multiple issues throughout Reliability Standards referring to any time duration.
Reporting ACE: Thank you for your comment. The SDT does not agree that a requirement for modeling asynchronous DC Tie Lines with
another Interconnection as source sink pairs should be required for reliability purposes. When managed as a source sink pair, the DC Tie
Line would have the same effect as any other load or generation, which is not required to be monitored in any specific standard.
R6: Thank you for your comment. The SDT determined that there is only one scan-rate value, for the Actual Frequency, used in
calculating the ACE for a single BA interconnection. The accuracy of Actual Frequency is covered in R3, and therefore, does not need to
be included in this requirement.
R4: Thank you for your comment. If the term is changed as you suggest, it would require the BA to make ACE available to all System
Operators (Generation, Transmission, and Reliability Coordinators) within their BA. This goes far beyond the intent of the requirement.
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34
R4 & R6: Thank you for your comment. BAL-005-1 appears to be on a faster timeline than TOP-010-1. If your suggestion is implemented
and BAL-005-2 is approved sooner than TOP-010-1, then there will be an interval without any requirement for an operating process or
data quality indication in the NERC standards. This situation would not be acceptable. The SDT defers to NERC staff for coordination
associated with the implementation timing of these standards.
R3: Thank you for your comment. The SDT does not agree that being available for the calculation of Reporting ACE is the same as
requiring Reporting ACE to be calculated. The SDT does not agree that R5 and R3 are linked in any way. Your interpretation would
require the system used to calculate Reporting ACE to be available 99.95% of the time instead of the 99.5% defined in R5.
Response
Dislikes
Likes
The VRF for R5 is listed as “Medium.” This appears to be an administrative function to calculate an entities prior year performance and
should be assigned a VRF of “Lower.”
BAL-005-2 R4 and R6 appear to be duplicative with R2 in the draft version of TOP-010-1. Reporting ACE and the inputs to it are obviously
Real-time data necessary to perform Real-time monitoring of the BES. LG&E/KU recommend that R4 and R6 be removed from the BAL005-2 standard and allow TOP-010-1 R2 to be the single Balancing Authority requirement addressing implementation of an Operating
Process or Procedure for Real-time data (which includes Reporting ACE and the scan rate data used to calculate Reporting ACE) quality
issues.
Frequency is a very important reliability parameter that should be monitored by the Balancing Authority. Currently, BAL-005.02b R8.1
requires that frequency metering be available 99.95% of the time. However, R3 of proposed BAL-005-2 requires frequency metering
to be available 99.95% of the time “for the calculation of Reporting ACE.” This added wording appears to create a possible overlap
compliance concern with R5. All Balancing Authorities understand the importance of redundant frequency metering and are today
required to maintain an availability (through automatic failover) of 99.95%. However, per the latest proposed BAL-005-2 standard not
only does frequency need to be available as a reliability parameter but it must be available “for the calculation of Reporting ACE.” If the
“system used to calculate Reporting ACE” (addressed in R5) is unavailable then a Balancing Authority could be found non-compliant with
both R3 and R5 despite having maintained frequency monitoring availability for any purpose at or above 99.95%. When compared to
today’s requirement to maintain a frequency monitoring availability of 99.95%, adding “for the calculation of Reporting ACE” provides no
reliability benefit given that the availability of the “system used to calculate Reporting ACE” is required to be 99.5%. LG&E/KU
recommends removing the language “for the calculation of Reporting ACE” from R3 as this added language provides no additional
reliability benefit.
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
R3.1: Thank you for your comment. The SDT agrees with your assessment that the 99.95% availability would be met with appropriate
frequency metering redundancy.
Response
Dislikes
Likes
Tacoma Power assumes that the intent of Requirement R7, Parts 7.1 and 7.2, is not to address the real-time status of common sources,
for either scan rate values or hourly megawatt-hour values, or for loss of time synchronization. It seems that these real-time
issues would be addressed under Requirement R2, Requirement R6, and/or other requirements and would not necessarily constitute a
violation of Requirement R7.
35
Could the drafting team please clarify how compliance with Requirement R3, Part 3.2, would be addressed if a Balancing Authority
periodically tests frequency metering equipment (e.g., annually) and finds that the equipment has fallen out of calibration since the last
test? For example, in the case of analog frequency transducers, in particular, the accuracy could stray over time. If a Balancing Authority
tests its frequency metering equipment periodically and discovers that the accuracy is now less than 0.001 Hz, the Balancing Authority
should not be in violation, since, in this scenario, it is not reasonable for them to have identifed the inaccuracy before the frequency
metering equipment went out of calibration.
Tacoma Power assumes that the intent of Requriement R3, Part 3.1, is that the total complement of frequency metering
equipment meets the availability specification. For example, if one frequency metering equipment has an availability of 99.94%, but
there is another frequency metering equipment available as a fail-over source such that availability of the redundant sources together is
equal to or higher than 99.95%, this should be considered compliant. Is this assumption reasonable?
Comment
Document Name
Answer
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
VFR for R5: Thank you for your comment. The SDT does not agree with your assessment. Reporting ACE is necessary to ensure reliability
and should be calculated continuously and therefore should have a VRF of Medium.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
R1 from BAL-005-0.2b should be retained in BAL-005-1 and re-written as follows:
We therefore once again urge the drafting team to consider retiring Requirements R1, R3, R4, R5 and R7 from BAL-005, and map them
into Organization Certification Requirements. While argument can be made to retain R6 as it drives the proper behavior to ensure data
errors are detected and mitigated, consideration may be given to also include this in the Organization Certification Requirements.
36
If arguments are made to have these requirements specifically stipulated, then such argument can be extended to include every data and
tool that an operating entity (including RC, TOP and GOP) uses to perform all of its tasks. If that’s the case, there will be no end to the
scope of this extension as this may include such data as PMU data, RTU data, voltage, current, MW, Mvar, frequency, etc., and tools such
as on-line contingency analysis, EMS programs, line loading estimators, load flow programs, dynamic simulation software, etc. For years,
operating entities have been relying on these data and tools to perform their tasks, and there have not been any notable events that
occurred due to inaccurate data or tool capability.
We continue to disagree with the majority of the requirements in the standard that stipulate the capabilities that a BA must have in order
to perform its reliability tasks. In our view, these are more suited for inclusion in the Organization Certification Requirements as opposed
to in Reliability Standards. The ongoing process to ensure accuracy of operating information and tools is an essential component of any
operating entity which provide such services and register with NERC as the responsible entity for complying with applicable Reliability
Standards. To have explicit requirements for having accuracy metering data at specific scan rate and availability (R1, R3 and R5), flagging
missing or invalid data (R4), having a process in place to detect and mitigate inaccurate or missing information (R6), and using common
source information between adjacent BAs (R7) are the fundamental organization requirements to enable a BA (and any operating entity)
perform its reliability tasks to meet its basic obligations.
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
R7: Thank you for your comment. The SDT agrees with your interpretation.
R3.2: Thank you for your comment. The SDT agrees with your assessment of discovering that metering equipment accuracy has fallen
out of adequate accuracy, assuming that the redundant frequency metering is used to replace the out of compliance metering as soon as
it is discovered.
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
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Answer
William Temple - William Temple
Actual Net Interchange: Thank you for your comment. The SDT decided that the inclusion of asynchronous DC tie lines in ACE will result
in ACE errors without offsetting benefits.
R3: Thank you for your comment. The SDT is of the opinion that your suggested wording is equivalent to the requirement as written.
37
R1: Thank you for your comment. The suggested R1 would be hard to enforce because there is no requirement that a BA be informed of
new or modified generation or transmission within its boundaries. This is the problem that the SDT is attempting to correct.
General: Thank you for your comment. The SDT does not agree with your position that, once certified, a BA will maintain these systems
without degradation since they are subject to continual modification.
Response
Dislikes
Likes
In the definition of Actual Net Interchange, strike the last sentence since it is too prescriptive. We believe a BA should have the flexibility
to either include or exclude the actual transfers across DC tie lines based on the modeling of the facility.
There was concerns about what quality the ± 0.001 Hz was being applied to.
3.3 checked for accuracy once each calendar year
3.2 that is rated to, and has a metering accuracy with a precision to ± 0.001 Hz.
3.1 that is available a minimum of 99.95% for each calendar year
R3. Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE:
CO-1 recommend the following wording for R3:
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area
is included within its metered boundaries.”
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
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If an availability requirement is needed, then we suggest tie it into the same time frame as the loss of ACE mandate.
Average availability (R3.1) on the other hand creates a reliability gap, and that as written does not increase reliability. Every lost scan
must be saved and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making
maintenance decisions, but as a standard use of average availability could be seen as establishing a reliability gap since some could even
say this is not a good use of computer time.
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable
requirement? PJM suggests that frequency meter accuracy be included in the certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good practice that when a BA control center is not functional that it tells the RC, but this is covered elsewhere. IRO-005-3.1a R1.6
requires the RC monitor “Current ACE for all its Balancing Authorities. ”
38
This requirement is not a reliability-based standard and is not needed. R2 addresses reporting the loss of ACE to an RC. The rationale
states this is important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and NET
Interchange). If a BA can’t compute its own ACE, then one of those three quantiles is unavailable. The RC does not rely on the BA for
frequency. NET tie flow is not used in any reliability studies (whereas individual tie flows would come from the TO) and NET Interchange is
a market issue - not a reliability issue.
REQUIREMENT 2
Additionally, if this standard is to remain, then the name of the standard should be changed. It is now referred to as Balancing Authority
Control, but the requirements are for ACE Process Design. BA Control is addressed by BAL requirements - not by this standard.
The new R1 is a design requirement and not something that is subject to change.
REQUIREMENT 1
PJM proposes that BAL-005 be translated into a certification requirement for the following reasons:
Comment
Document Name
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
PJM notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The
same integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized”
from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
The term “scan-rate” should be changed to “scan rate.” Nowhere else in the standard or the NERC glossary is this term hyphenated.
Requirement R6 is confusing regarding the term “errors.” Are these metering errors such as spikes? Are these Inadvertent Interchange
metering errors? The requirement should provide more clarity on this.
On the other hand, it is possible to have a process to handle no ACE values.
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process.” Is it
more important to have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
3.2 that is rated to, and has a metering accuracy with a precision to ± 0.001 Hz.
3.1 that is available a minimum of 99.95% for each calendar year
R3. Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE:
PJM believes the requirement should be removed. However if the requirement is not removed PJM submits the following re-wording of
R3 for clarity:
b. R3 could also be misinterpreted to mean that a BA’s frequency error over an entire year must be 0.001 HZ or less.
a. With the way R3 reads, it could be misinterpreted that the frequency metering equipment requires an accuracy of 0.001 Hz for
99.95% of the calendar year. That would mean checking (and fixing) your frequency metering device every hour to ensure you do not
exceed four hours during a year with a frequency accuracy less than 0.001 Hz. This is not intent of R3 and the requirement should be
rewritten. The intent is that the frequency metering equipment is designed to have a minimum accuracy of 0.001 Hz.
There are two concerns with the way R3 is worded:
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R7: Thank you for your comment. New tie lines and tie line metering are being added and modified on an ongoing basis. This is more
than a design requirement; it requires that the metering and metering methods be maintained on an ongoing basis. As long as some BAs
have time synchronized metering for accumulated MWh this requirement should remain. The requirement for a common source has not
been changed from the previous version of the standard, BAL-005-0.2b R12.1. “Tie Line” is the term used within the Glossary of terms
and the SDT will make the change.
R6: Thank you for your comment. The SDT is unclear about your observation and therefore has no suggested change. The SDT will
change “scan-rate” to “scan rate”.
R3: Thank you for your comment. The SDT is more concerned about the accuracy than the rating of the equipment. Rating of the
equipment does not necessarily guarantee the accuracy of the equipment.
R2: Thank you for your comment. The transmission of an ACE value to the Reliability Coordinator does not guarantee that the Reliability
Coordinator will be aware of the loss of the ability to calculate ACE when that occurs. This requirement assures that that information is
available to the RC.
R1: Thank you for your comment. In the early days of EMS development, it was common practice to extend the scan rate to manage
additional data or calculations. A six second design does not guarantee a six second scan rate for the life of the EMS.
Standard Name: Thank you for your comment. The SDT chose the new name for the standard. This is the first suggestion that it be
changed. The SDT believes the current name is more reflective of the standard.
Response
Dislikes
Likes
In R7.2, PJM’s concern here is that errors would be apparent in many more ways (and much more quickly) than by calculating hourly
megawatt-hour values. This doesn’t appear to be a reliability requirement.
In R7, the word Tie-Line is not defined. In the NERC Glossary it is listed as “Tie Line.”
R7 requires the BAs to have a common source. This could possibly pose a conflict with CIP-005-5 R1, which could be interpreted to
require a Responsible Entity to have individual access to a meter.
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Likes
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If for any reasons Requirement R3 is retained, then we would suggest rewording it to improve clarity. As written, R3 can be
interpreted as a continuous accuracy requirement of 0.001 Hz under all conditions including use of secondary or tertiary backup
equipment when necessary under certain conditions. We do not believe this is the intent of the requirement so it needs to be reworded to not imply a continuous accuracy requirement. If the intent is to use primary frequency metering equipment that has
demonstrated or been tested to meet the 0.001 Hz accuracy requirement, then the requirement and/or the measure should be revised
to clearly indicate this is the objective/intent.
We therefore once again urge the drafting team to consider retiring Requirements R1, R3, R4, R5 and R7 from BAL-005, and map them
into Organization Certification Requirements. While argument can be made to retain R6 as it drives the proper behavior to ensure data
errors are detected and mitigated, consideration may be given to also include this in the Organization Certification Requirements.
If arguments are made to have these requirements specifically stipulated, then such argument can be extended to include every data
and tool that an operating entity (including RC, TOP and GOP) uses to perform all of its tasks. If that’s the case, there will be no end to
the scope of this extension as this may include such data as PMU data, RTU data, voltage, current, MW, Mvar, frequency, etc., and
tools such as on-line contingency analysis, EMS programs, line loading estimators, load flow programs, dynamic simulation software,
etc. For years, operating entities have been relying on these data and tools to perform their tasks, and there have not been any
notable events that occurred due to inaccurate data or tool capability.
We continue to disagree with the majority of the requirements in the standard that stipulate the capabilities that a BA must have in
order to perform its reliability tasks. In our view, these are more suited for inclusion in the Organization Certification Requirements as
opposed to in Reliability Standards. The ongoing process to ensure accuracy of operating information and tools is an essential
component of any operating entity which provides such services and registers with NERC as the responsible entity for complying with
applicable Reliability Standards. To have explicit requirements for having accuracy metering data at specific scan rate and availability
(R1, R3 and R5), flagging missing or invalid data (R4), having a process in place to detect and mitigate inaccurate or missing
information (R6), and using common source information between adjacent BAs (R7) are the fundamental organization requirements to
enable a BA (and any operating entity) performs its reliability tasks to meet its basic obligations.
Comment
Document Name
Answer
Leonard Kula - Independent Electricity System Operator - 2
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Jeri Freimuth - APS - Arizona Public Service Co. - 3
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Actual Net Interchange: Thank you for your comment. The SDT decided that the inclusion of asynchronous DC tie lines in ACE will result
in ACE errors without offsetting benefits.
R3: Thank you for your comment. The SDT is of the opinion that your suggested wording is equivalent to the requirement as written.
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R1: Thank you for your comment. The suggested R1 would be hard to enforce because there is no requirement that a BA be informed of
new or modified generation or transmission within its boundaries. This is the problem that the SDT is attempting to correct.
General: Thank you for your comment. The SDT does not agree with your position that, once certified, a BA will maintain these systems
without degradation since they are subject to continual modification.
Response
Dislikes
0
Thank you for your comment. The SDT chose to eliminate interchange because it is included in resources.
0
The proposed version of BAL-005 is inconsistent with the recommendations of the Independent Experts Review Project and the
Results-Based Reliability Standard Development Guidance.
R1, R3, and R7 are design parameters and should be moved to a Guideline (and reviewed as part of a BA Certification). They are
not performance-based, risk-based, or competency-based requirements.
R4 seems to overlap the proposed TOP-010-1 R2 creating a potentially double-jeopardy.”
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Likes
x
x
x
Comment
Document Name
Answer
Donald Hargrove - OGE Energy - Oklahoma Gas and Electric Co. – 3
2.
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Thank you for your comment. The SDT modified Requirement R7 Part 7.2 to clarify the intent. The SDT believes
Requirement R7 Part 7.2 does not have two requirements. The SDT believes the requirement that you have suggested should be
a separate requirement for compliance purposes would be part of the Operating Process as developed in Requirement R6.
“Agreed upon” is necessary to aid in the identification of errors and assignment of the errors to the appropriate BA for mitigation
as necessary under the Operating Process developed in Requirement R6.
1.
Response
Dislikes
0
The wording of R7.2 appears to be combining two requirements. The requirement to have a time-synchronized common source
and to agree upon the hourly megawatt-hour values the source provides. These should be separated out as the current verbiage
is unclear.
2.
Likes
Although it can be viewed as a “resource”, maintaining Interchange obligations is a unique enough task for a Balancing Authority
to perform, APS recommends leaving Interchange in as part of the Balancing Authority definition. “…maintains Demand and
resource balance within a Balancing Authority Area, while maintaining Interchange obligations, and supports Interconnection
frequency in real time.”
1.
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Likes
M1. Each Balancing Authority will have dated documentation demonstrating that the data necessary to calculate Reporting ACE was
designed to be scanned at a rate not greater than six seconds. Acceptable evidence may include historical data, dated archive files; or
data from other databases, spreadsheets, or displays that demonstrate compliance.
R1. The Balancing Authority shall use a design scan rate not greater than six seconds in acquiring data necessary to calculate Reporting
ACE. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
Southern Suggests adding the below wording to R1 and M1:
The responsible entity that integrates resource plans ahead of time, maintains Demand and resource balance within a Balancing
Authority Area, while maintaining scheduled interchange and supporting Interconnection frequency in real time.
Southern suggests adding the below wording to the definition of Balancing Authority:
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
R4: Thank you for your comment. BAL-005-1 appears to be on a faster timeline than TOP-010-1. If your suggestion is implemented and
BAL-005-2 is approved sooner than TOP-010-1, then there will be an interval without any requirement for an operating process or data
quality indication in the NERC standards. This situation would not be acceptable. The SDT defers to NERC staff for coordination
associated with the implementation timing of these standards.
R1, R3 & R7: Thank you for your comment. The SDT does not agree with your position that, once certified, a BA will maintain these
systems without degradation since they are subject to continual modification.
General: Thank you for your comment. The SDT does not agree with your position that, once certified, a BA will maintain these systems
without degradation since they are subject to continual modification.
Response
Dislikes
44
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
The rationale states this is important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and
NET Interchange). If a BA can’t compute its own ACE then one of those three quantiles is unavailable. The RC does not rely on the BA for
R2 addresses reporting the loss of ACE to an RC.
This requirement is not a reliability based standard and is not needed.
REQUIREMENT 2
Also, if this standard is to remain then the name of the standard should be changed. It is now referred to as Balancing Area Control but
the requirements are for ACE Process Design. BA Control is addressed by BAAL requirements not by this standard.
The new R1 is a design requirement and not something that is subject to change
REQUIREMENT 1
The SRC proposes that BAL-005 be translated into a certification requirement for the following reasons:
ERCOT supports the comments of the IRC SRC. The comments are provided below:
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
R1: Thank you for your comment. In the early days of EMS development, it was common practice to extend the scan rate to manage
additional data or calculations. A six second design does not guarantee a six second scan rate for the life of the EMS.
Balancing Authority: Thank you for your comment. The SDT is of the opinion that your suggested wording is equivalent to the
requirement as written, so no change is currently necessary.
Response
Dislikes
45
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process” Is it
more important to have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
46
Requirement 5 like Requirement 3.1 mandates an average availability. The concern that should be raised is that of mandating an average
availability value. If a BA has 100% availability it can stop calculating ACE for the entire last day of the year and still be compliant! Average
availability is a make work requirement. Every lost scan must be saved and summed over a year. If one were inclined to want an
availability mandate then why not tie it into the same time frame as the loss of ACE mandate?
REQUIREMENT 5
Requirement 4 is a fill-in-the-blanks standard unless the SDT defines what constitutes “invalid data” and defines “quality” (if the BA is to
flag quality then the term should be defined somewhere)
REQUIREMENT 4
If an availability mandate is needed, then why not tie it into the same time frame as the loss of ACE mandate?
Average availability (R3.1) on the other hand creates a realibilty gap, and that as written is a make work requirement. Every lost scan
must be saved and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making
maintenance decisions, but as a standard use of average availability could be seen as establishing a reliability gap since some could even
say this is not a good use of computer time!
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable requirement? The
SRC would suggest that frequency meter accuracy is better left to a certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good idea that when a BA control center is not functional that it tells the RC but isn’t that fact covered elsewhere, such as IRO-0053.1a R1.6 mandating that the RC monitor “Current ACE for all its Balancing Authorities.”?
frequency. NET tie flow is not used in any reliability studies (whereas individual tie flows would come from the TO) and NET Interchange is
a market issue not a reliability issue. Why then should the BA be mandated to tell the RC that it can’t calculate ACE?
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
R5: Thank you for your comment. Since CPS1 is based upon annual average ACE performance and is the primary measure of control
compliance, it makes sense to require availability over the same or a similar time period to support that measure.
R4: Thank you for your comment. Invalid data and data quality flags have been used in EMS since they were first developed. The SDT
does not think these terms require definition.
47
R3: Thank you for your comment. History has demonstrated that frequency measurement devices can and do deviate from specification
and require recalibration or replacement. It would be foolish to assume that once certified they no longer need to be addressed.
R2: Thank you for your comment. The transmission of an ACE value to the Reliability Coordinator does not guarantee that the Reliability
Coordinator will be aware of the loss of the ability to calculate ACE when that occurs. This requirement assures that that information is
available to the RC.
R1: Thank you for your comment. In the early days of EMS development, it was common practice to extend the scan rate to manage
additional data or calculations. A six second design does not guarantee a six second scan rate for the life of the EMS.
Standard Name: Thank you for your comment. The SDT chose the new name for the standard. This is the first suggestion that it be
changed.
Response
Dislikes
Likes
The SRC notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The
same integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized”
from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
On the other hand, it is possible to have a process to handle no ACE values.
Each BA shall support Interconnection frequency through monitoring Reporting ACE
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
R1 &R2: Thank you for your comment. The SDT believes the suggestion would result in a standard with undefined and unauditable
requirements which could negatively impact reliability.
Response
Dislikes
Likes
R2.
A Balancing Authority shall maintain adequate metering, communications, and control equipment to prevent becoming a Burden
on the Interconnection or other Balancing Authority Areas.
R1.
We suggest the Standard be completely revisited to be:
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
48
R7: Thank you for your comment. New tie lines and tie line metering is being added and modified on an ongoing basis. This is more than
a design requirement, it requires that the metering and metering methods be maintained on an ongoing basis. As long as some BAs have
time synchronized metering for accumulated MWh this requirement should remain. The requirement for a common source has not been
changed from the previous version of the standard, BAL-005-0.2b R12.1.
R6: Thank you for your comment. The Operating Process is not defined in the requirement. Any appropriate process that manages
errors in ACE and the data to support the calculation of ACE will be acceptable. However, a process that handles every scan error may
deviate from the principles of good quality control and result in detrimental tampering with the system.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Average availability (R3.1) on the other hand creates a realibilty gap, and that as written is a make work requirement. Every lost scan
must be saved and summed over a year. Use of average availability is a good spot check for a Functional Entity to use in making
49
Establishing minimum limits on meter accuracy (R3.2) can be rationalized, but is there a need to make this an auditable requirement? The
SRC would suggest that frequency meter accuracy is better left to a certification process.
The requirement defines (frequency) equipment accuracy and availability.
REQUIREMENT 3
It is a good idea that when a BA control center is not functional that it tells the RC but isn’t that fact covered elsewhere, such as IRO-0053.1a R1.6 mandating that the RC monitor “Current ACE for all its Balancing Authorities.”?
The rationale states this is important to the RC as it relates to reliability. ACE has only a few moving parts (frequency, NET tie flow and
NET Interchange). If a BA can’t compute its own ACE then one of those three quantiles is unavailable. The RC does not rely on the BA for
frequency. NET tie flow is not used in any reliability studies (whereas individual tie flows would come from the TO) and NET Interchange is
a market issue not a reliability issue. Why then should the BA be mandated to tell the RC that it can’t calculate ACE?
R2 addresses reporting the loss of ACE to an RC.
This requirement is not a reliability based standard and is not needed.
REQUIREMENT 2
Also, if this standard is to remain then the name of the standard should be changed. It is now referred to as Balancing Area Control but
the requirements are for ACE Process Design. BA Control is addressed by BAAL requirements not by this standard.
The new R1 is a design requirement and not something that is subject to change
REQUIREMENT 1
The SRC proposes that BAL-005 be translated into a certification requirement for the following reasons:
Comment
0
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January 28, 2016
Response
Dislikes
Likes
50
The SRC notes that not all tie lines have time-synchronized meters. Adjacent BAs just need to operate to common real time meters. The
same integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized”
from the requirement.
R7 is a design requirement and not something that is subject to change.
REQUIREMENT 7
On the other hand, it is possible to have a process to handle no ACE values.
Requirement 6 would seem to be misplaced. R6 requires the BA to have a process for “correcting errors in the scanning process” Is it
more important to have a process that can address every cause of every scanning error? Is it even possible?
REQUIREMENT 6
Requirement 5 like Requirement 3.1 mandates an average availability. The concern that should be raised is that of mandating an average
availability value. If a BA has 100% availability it can stop calculating ACE for the entire last day of the year and still be compliant! Average
availability is a make work requirement. Every lost scan must be saved and summed over a year. If one were inclined to want an
availability mandate then why not tie it into the same time frame as the loss of ACE mandate?
REQUIREMENT 5
Requirement 4 is a fill-in-the-blanks standard unless the SDT defines what constitutes “invalid data” and defines “quality” (if the BA is to
flag quality then the term should be defined somewhere)
REQUIREMENT 4
If an availability mandate is needed, then why not tie it into the same time frame as the loss of ACE mandate?
maintenance decisions, but as a standard use of average availability could be seen as establishing a reliability gap since some could even
say this is not a good use of computer time!
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
51
R7: Thank you for your comment. New tie lines and tie line metering is being added and modified on an ongoing basis. This is more than
a design requirement, it requires that the metering and metering methods be maintained on an ongoing basis. As long as some BAs have
time synchronized metering for accumulated MWh this requirement should remain. The requirement for a common source has not been
changed from the previous version of the standard, BAL-005-0.2b R12.1.
R6: Thank you for your comment. The Operating Process is not defined in the requirement. Any appropriate process that manages
errors in ACE and the data to support the calculation of ACE will be acceptable. However, a process that handles every scan error may
deviate from the principles of good quality control and result in detrimental tampering with the system.
R5: Thank you for your comment. Since CPS1 is based upon annual average ACE performance and is the primary measure of control
compliance, it makes sense to require availability over the same or a similar time period to support that measure.
R4: Thank you for your comment. Invalid data and data quality flags have been used in EMSs since they were first developed. The SDT
does not think these terms require definition.
R3: Thank you for your comment. History has demonstrated that frequency measurement devices can and do deviate from specification
and require recalibration or replacement. It would be unwise to assume that once certified they no longer need to be addressed.
R2: Thank you for your comment. The transmission of an ACE value to the Reliability Coordinator does not guarantee that the Reliability
Coordinator will be aware of the loss of the ability to calculate ACE when that occurs. This requirement assures that that information is
available to the RC.
R1: Thank you for your comment. In the early days of EMS development, it was common practice to extend the scan rate to manage
additional data or calculations. A six second design does not guarantee a six second scan rate for the life of the EMS.
Standard Name: Thank you for your comment. The SDT chose the new name for the standard. This is the first suggestion that it be
changed.
0
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
52
R7: Thank you for your comment. If the meters used for determining MWh values are not time synchronized, then the Operating Process
required in R6 would not be valid. Time synchronization is intended to include all forms, such as accumulator freeze pulses, and not to
require a specific time synchronizing mechanism. As long as some BAs have time synchronized metering for accumulated MWh this
requirement should remain.
Response
Dislikes
Likes
R7.2 Not all tie lines have time-synchronized meters. The adjacent BAs just need to operate to common real time meters. The same
integrated value for the hour should be transmitted to both BAs at the end of each hour. Remove the term “time synchronized” from the
requirement.
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
R1: Thank you for your comment. The suggested R1 would be hard to enforce because there is no requirement that a BA be informed of
new or modified generation or transmission within its boundaries. This is the problem that the SDT is attempting to correct.
Response
Dislikes
Likes
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area
is included within its metered boundaries.”
R1 from BAL-005-0.2b should be retained in BAL-005-1 and re-written as follows:
R3 is vague and has the potential for inconsistent implementation as worded.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Document Name
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
R6: Thank you for your comment. As written the SDT is using two separate defined terms not creating a “super term”.
R5: Thank you for your comment. Different methods of determining the 99.5% availability may be appropriate for different EMS and
different BAs.
R4: Thank you for your comment. If the term is changed as you suggest, it would require the BA to make ACE available to all System
Operators (Generation, Transmission, and Reliability Coordinators) within their BA. This goes far beyond the intent of the requirement.
R3: Thank you for your comment. The 99.95% only applies to the frequency metering.
Response
Dislikes
0
R6 – SRP recommends rewording the standard to avoid creating the super tem “Balancing Authority Interconnection.
·
0
R5 – SRP recommends providing clarification on how the 99.5% is to be calculated?
·
Likes
R4 – SRP recommends reducing ambiguity by adjusting the requirement to state “System Operator”.
·
It is unclear whether the 99.95% availability calculation is to be applied independently to each individual metering point, or whether it
should be the average availability of all metering equipment.
·
SRP appreciates the efforts of the SDT and provides the following comments regarding the changes to BAL-005-1:
Comment
Document Name
Answer
53
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Response
Dislikes
Likes
Provided in ACES Comments
Comment
54
0
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Response
Dislikes
Likes
SRP is in support of retiring BAL-006-2
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Response
Dislikes
Likes
na
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
3. If you are not in support of the retirement of BAL-006-2 and the development of a guideline, please provide your objection(s) and
proposed solution(s) in the area below.
55
0
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Southern supports the retirement of BAL-006-2. However, we suggest requirements be included in a commercial alternative
arrangement, such as a NAESB standard, rather than a guideline that only suggests approaches and behaviors and is not binding or
mandatory.
Comment
Document Name
Answer
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Response
Dislikes
Likes
ERCOT joins the IRC SRC in supporting the retirement of BAL-006.
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Response
Dislikes
Likes
The SRC supports the retirement of BAL-006-2.
Comment
Document Name
56
0
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
PJM supports the retirement of BAL-006.
Comment
Document Name
Answer
William Temple - William Temple
Thank you for your support.
Response
Dislikes
Likes
Duke Energy supports the retirement of BAL-006-2 in conjunction with the changes in BAL-005 as well as the development of the
Guideline document as an integrated package. We feel that implementation of just one of these suggestions, without the others, would
not sufficiently maintain reliability concerns with the grid.
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Thank you for your support. The drafting team considered the NAESB alternative, however, since the information process is currently
under the NERC OC subcommittee RS, we felt it was more seamless to maintain it under a guideline.
Response
Dislikes
Likes
57
0
0
0
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Likes
: LG&E/KU would like to support the retirement of BAL-006 but as of now have questions regarding the guideline and implementation
plan. For example, in the transition to a guideline, must existing inadvertent balances be minimized or do existing balances simply
disappear?
Comment
Document Name
Answer
Brent Ingebrigtson - LG&E and KU Energy, LLC - 1,3,5,6 - SERC
Thank you for your support.
Response
Dislikes
Likes
We support the retirement of BAL-006-2.
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Thank you for your support.
Response
Dislikes
Likes
58
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
59
The SDT intends to file the proposed modifications prior to July 1, 2016 in compliance with the FERC directive. In addition, the proposed
modification to the Reporting ACE definition incorporating thee ATEC term has no impact on reliability since the WECC Regional Standard
includes the ATEC definition.
Thank you for your comment. The SDT has made clarifying modifications to the Implementation Plan for BAL-005-1 based on the
information supplied in the retirement section.
Response
Dislikes
Likes
Additionally, the BAL-005-1 Implementation Plan lacks clarity on effective dates for the Standards and definitions in question. BAL-001-2
is effective July 1, 2016. There may not be an approval on definitions contained within BAL-005-1 before that time period. Additionally
the SDT is unclear if the definitions would apply to BAL-005-0.2b, which could still be in effect after BAL-001-2 is in effect but before BAL005-1 becomes effective. A CEA will have to evaluate the Standards and definitions that are FERC approved, not proposed, for
compliance monitoring efforts.
In the BAL-005-1 Implementation Plan there is a reference to retirement of BAL-006-2 under “General Considerations” but further down
there is a reference to BAL-006-2 Requirement 3 under “Retirements”. Additionally, there is no reference to BAL-006-2 in the “Requested
Retirement” section. Which is correct?
Comment
Document Name
Answer
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Thank you for your support. Since the balances are more commercial and have no impact on past reliability, the drafting team feels these
are financial issues that could be resolved through standard business means.
Response
Dislikes
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Thank you for your support.
Response
Dislikes
Likes
We agree with the SDT in proposing to retire BAL-006-2 and to develop an Inadvertent Interchange Guideline that will be approved by
the NERC Operating Committee at a later date.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Response
Dislikes
Likes
N/A
Comment
Document Name
Answer
60
0
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Thank you for your support. The drafting team considered the NAESB alternative, however, since the information process is currently
under the NERC OC subcommittee RS, we felt it was more seamless to maintain it under a guideline.
Response
Dislikes
Likes
BPA agrees that BAL-006-2 is an energy accounting standard and not a Reliability Standard. However, guidelines are not
enforceable. BPA agrees it is important to maintain requirements to calculate and account for Inadvertent Interchange. BPA proposes
adding inadvertent accounting via a NAESB standard or business practice since the NAESB WEQ Inadvertent Interchange Payback
Standards already handles certain aspects of Interchange accounting.
61
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
62
The Implementation Plan determines when you must have these procedures in place, not how long you have to conclude your
interconnection study request. The proposed changes only require the addition of procedures to confirm the entity is within the metered
The Drafting Team respectfully disagrees that having Facilities within the metered boundaries of a Balancing Authority Area is
administrative in nature. Generation operating outside the boundaries of any Balancing Authority must, itself, become a Balancing
Authority by definition. Otherwise, it is detrimental to the Bulk Electric System by influencing Frequency with a source unknown to the
rest of the Interconnection and the Reliability Coordinator. NERC requires all Facilities within the interconnected network to be within a
Balancing Authority Area when they are being placed in service. Therefore, the Transmission Operator and the Balancing Authority must
be informed by the asset owner and a Standard Interconnection Agreement signed prior to any operation (commercial or otherwise).
(4) We thank the SDT for the opportunity to comment on this standard.
(3) We recommend extending the implementation plan to 36 months. The proposed 12-month implementation plan is insufficient
because interconnection study requests can take as long as 18 months. These could take significant amounts of time if complex issues
are encountered during negotiations of interconnection agreements.
(2) However, we disagree with other proposed modifications in FAC-001-3. It was determined through the Paragraph 81 project that
having Facilities within a BA’s metered area boundaries are administrative and unnecessary. We suggest removing Requirement R3, part
3.3 and Requirement R4, part 4.3. These are administrative requirements that are not necessary for reliability. Furthermore, the NERC
Rules of Procedure Section 501.4.4 already requires NERC to “ensure that all Loads and generators are under the responsibility and
control of one and only one Balancing Authority.” There are equally efficient means that are already in effect; therefore, the SDT should
remove these requirements, as they are unnecessary.
(1) We agree with the removal of the LSE function.
Comment
Document Name
Answer
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
4. If you are not in support of the proposed modifications to FAC-001-3, please provide your objection(s) and proposed solution(s) in
the area below.
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
You are correct that these requirements align with those from BAL-005-0.2b. These requirements were relocated from that standard as
part of this project. Therefore they will not be duplicative as they are replacing them.
There currently is a separate active NERC project to align terms in the ROP and Glossary of Terms. It is outside the purview of this team
to align terms between these documents. This Drafting Team contains members from both projects in an effort to help correct any
incongruence. The Drafting Team believes the Rationale boxes adequately explain that Transmission Owners are not necessarily
Balancing Authorities and, therefore, these roles must be defined and fulfilled prior to operations.
63
Its not that we aren’t in support of the modifications to FAC-001 however, we have a concern that the documentation mentioned in
Rationale 3.3 and 4.3 (Functional Model) isn’t currently up to date. We would suggest to the drafting team to verify the latest review of
this documentation. Also, we would suggest the drafting team verifying that this document is properly aligned with other documentation
such as: The Rules of Procedure (ROP), Glossary of Terms and The Federal Power Act for consistency and reliability of the BES.
Additionally, we would like for the drafting team to review the concept that all generation, transmission, and load must be within the
metered bounds of a BA is a control area criteria that pre-dates the NERC standards. It is a concept that comes about by operating to
common meters. It is therefore redundant and unnecessary to explicitly state that all facilities must be within a BA in association
referenced to BAL-005-0.2b Requirement R1 parts R1.1, R1.2 and R1.3. A FAC-001-3 requirement to have verification of this will just lead
to a paper exchange where TOPs, GOPs, and Loads will be asking BAs for pieces of documentation that they are within a given BA or to
sign agreements that acknowledge the facility is within a BA. Keep in mind this includes each and every load, every piece of transmission,
and every generator. This provides no reliability value.
Comment
Document Name
Answer
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP, Group Name SPP Standards Review Group
Dislikes
Likes
boundaries of a Balancing Authority. That would have no impact on the duration of an interconnection study since the studies do not
consider who the BAA is for a facility.
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The drafting team has made conforming modifications to Requirement R3.3 to accurately reflect the intent of the drafting team, as
described in the Rationale for R3.3. As stated in the Rationale, “it is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries, which also serves to facilitate the
process of the coordination between the two entities that will be required under numerous other standards upon the start of operation.”
Additionally, the “Transmission Owner is responsible for confirming that the party interconnecting has made appropriate provisions with
R3.3
As currently written in Draft 2, R3, part 3.3, appears to focus on “transmission Facilities” and ignores generation Facility and end-user
Facility connections. Similarly, R4, part 4.3, appears to focus on “generation Facilities” and ignores transmission Facility and end-user
Facility connections.
R4, part 4.3: Procedures for confirming that the party seeking a new or materially modified interconnection has made appropriate
provisions with a Balancing Authority to operate within that Balancing Authority Area’s metered boundary.
R3, part 3.3: Procedures for confirming that the party seeking a new or materially modified interconnection has made appropriate
provisions with a Balancing Authority to operate within that Balancing Authority Area’s metered boundary.
While TVA supports the intent of addressing the metered boundaries of the Balancing Authority Area in FAC-001-3, we believe the
language of R3, part 3.3, and R4, part 4.3, needs to be improved. We recommend that wording similar to that used in the rationale
statements be used in the requirement sub-parts as follows:
Comment
Document Name
Answer
Joel Wise - Tennessee Valley Authority - 1,3,5,6 - SERC
Dislikes
Likes
Although the process to confirm that all Facilities reside within the metered boundaries of a BAA will use administrative means to be
accomplished and evidenced, it does not take away from the importance of confirming that such relationships exists prior to operation.
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FAC-001-2 was revised in 2013 to eliminate any requirements that were not necessary for reliability according to FERC paragraph 81
directions. As a member of the FAC-001-2 SDT charged with this task, GTC along with the other members followed the directives of FERC
Comment
Document Name
Answer
Jason Snodgrass - Georgia Transmission Corporation - 1
Dislikes
Likes
The drafting team has made conforming modifications to Requirement R4.3 to accurately reflect the intent of the drafting team, as
described in the Rationale for R4.3. As stated in the Rationale, “it is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries, which also serves to facilitate the
process of the coordination between the two entities that will be required under numerous other standards upon the start of operation.”
Additionally, the “Generator Owner is responsible for confirming that the party interconnecting has made appropriate provisions with a
Balancing Authority to operate within its metered boundaries.” By removing the term “generation,” Requirement R4.3 more clearly
reflects the fact that a Generator Owner properly addresses procedures for confirming that those responsible for reliability of the
applicable affected systems are within a Balancing Authority Area’s metered boundaries. This change promotes reliability because it
ensures confirmation that all entities that affect reliability share relevant information because they are within a Balancing Authority
Area’s metered boundaries.
R4.3
a Balancing Authority to operate within its metered boundaries.” By removing the term “transmission,” Requirement R3.3 more clearly
reflects the fact that a Transmission Owner properly addresses procedures for confirming that those responsible for reliability of the
applicable affected systems are within a Balancing Authority Area’s metered boundaries. This change promotes reliability because it
ensures confirmation that all entities that affect reliability share relevant information because they are within a Balancing Authority
Area’s metered boundaries.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator Owners
must document and make Facility interconnection study requirements available so that entities seeking to interconnect will provide the
information necessary for studies conducted in accordance with FAC-002-2.
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Therefore, GTC respectfully requests this drafting team to remove R3.3 and R4.3 as a proposed change to FAC-001-2 and further clarify
the purpose statement of FAC-001 to resolve the ambiguity that this current draft introduced by clarifying the purpose of FAC-001 which
should align with FAC-002 by inserting the term “study” within the purpose statement such as:
In summary, GTC believes that the proposed requirements FAC-001-3-R3.3 and FAC-001-3-R4.3 address specific needs for operating the
system and therefore belong in an Operations Standard which is already being covered in requirements of FERC approved TOP-003-3
which describes the information that TOs and GOs are required to provide to the Balancing Authority as specified by the Balancing
Authority.
Based on the Ballot supporting material, the proposed FAC-001 R3.3 and R3.4 requirements were originally included in BAL-005-1. The
goal of the requirement in BAL-005-1 was to ensure that Area Control Error is calculated properly. Although GTC sees a merit in ensuring
that the Area Control Error is calculated properly, GTC believes that the proposed requirements (FAC-001-3-R3.3, R4.3) would violate
paragraph 81 criteria and introduces ambiguity associated with the aforementioned planning horizon vs operations horizon concerns that
is currently not addressed in FAC-001 or FAC-002. GTC believes this concern is already covered in operation horizon standards such as
TOP-003-3. Specifically, R4 of TOP-003-3 already addresses and requires the BA to distribute its data specification to entities that have
data required by the BA analysis functions and Real-time monitoring. Additionally, R5 of TOP-003-3 requires each TOP, GO, GOP, TO, LSE,
and DP to satisfy the obligations of the documented specifications.
All of the requirements of FAC-001 are limited to the long-term planning time horizon. Based on the rationale and proposed language
provided for R3.3 and R4.3, a new level of ambiguity has presented itself that could lead some to conclude that these interconnection
requirements should be expanded beyond the planning horizon and lead up to “commissioning of a Facility” which resides in the
operations horizon.
Additionally, GTC understands that FAC-001 and FAC-002 are complimentary Standards in a sense that FAC-001 requires Transmission
Owners or Generator Owners to define the interconnection requirements necessary to collect data from entities such that the Planning
Coordinator and Transmission Planners can study the impact of interconnecting new or materially modified Facilities to the BES in
accordance with FAC-002.
and retained only the requirements necessary for system reliability. As such 14 sub-requirements in FAC-001 were removed including a
requirement for metering and telecommunication.
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If the SDT chooses to retain these requirements, some changes in the wording are warranted: R3.2 reads, “Procedures for notifying those
responsible for the reliability of affected system(s) of new or materially modified existing interconnections.” In order to understand the
sentence, it is helpful to make a substitution like the following: “Procedures for notifying [someone] of new [things].”
While the latest proposed revisions to FAC-001-3 are an improvement (by removing the unnecessary R5, R6 and R7), the additions of R3.3
and R4.3 could be better worded, are unnecessary as requirements (they attempt to address an energy accounting problem, not a
reliability problem), and likely already included in most Facility Interconnection Requirements documents in the Metering and
Telecommunications section under Guidelines and Technical Basis (created in the new FAC-001-2), and/or in interconnection agreements
between Facility owners and transmission providers.
Comment
Document Name
Answer
Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1
Dislikes
Likes
Since the requirements currently exist in BAL-005 and were not eliminated as part of P81, there is no debate that they are reliability
based. The Drafting Team is proposing relocating them to FAC-001. Unfortunately, the TOP-003-3 data specification would not serve to
confirm that a Facility is within the metered boundary of a BAA. Those data specifications are established to truly operate in real-time.
The determination that a Facility is within the metered boundaries of a BAA must be determined prior to a new Facility operating.
Although the determination that a Facility is within a BAA serves real-time operations, that does not preclude the confirmation of it
occurring early than at that time. For example, Seasonal Studies are conducted to assure that proper planning occurs to allow for realtime operations. This confirmation of which BAA will have the Facility within its boundaries occurring during the planning and studying
stage is appropriate too since reconciliation of concerns may need to be addressed with this entity.
It is GTC’s desire that the drafting team utilizes the justification provided by GTC to not move forward with the proposed R3.3 and R3.4
and a refer to TOP-003-3 to demonstrate that there is currently not a reliability gap and also take the time to clarify the purpose
statement to resolve the ambiguity introduced with this revision which should not prevent the drafting teams goal of an approved ballot.
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Additionally, GTC understands that FAC-001 and FAC-002 are complimentary Standards in a sense that FAC-001 requires Transmission
Owners or Generator Owners to define the interconnection requirements necessary to collect data from entities such that the Planning
Coordinator and Transmission Planners can study the impact of interconnecting new or materially modified Facilities to the BES in
accordance with FAC-002.
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FAC-001-2 was revised in 2013 to eliminate any requirements that were not necessary for reliability according to FERC paragraph 81
directions. As a member of the FAC-001-2 SDT charged with this task, GTC along with the other members followed the directives of FERC
and retained only the requirements necessary for system reliability. As such 14 sub-requirements in FAC-001 were removed including a
requirement for metering and telecommunication.
Comment
Document Name
Answer
Teresa Czyz - Georgia Transmission Corporation - 1,3 - SERC
Dislikes
Likes
Thank you for the suggested language to make the requirement read better. The SDT has made the modification as suggested.
Although this information may be included in some Interconnection Requirements, it is not mandated to be in all. If it is already included
in those documents, then the entity will likely have little more to do.
The Drafting Team does not agree that each Facility being within the metered boundaries of a BAA is an energy accounting issue. If a
Facility is not within a BAA, for example a generator, it can cause many reliability issues such as impacting Frequency and flows. This has
occurred in the past, which proves the need for this requirement to remain.
The new R3.3 reads: “Procedures for confirming with those responsible for the reliability of affected systems of new or materially
modified transmission Facilities are within a Balancing Authority Area’s metered boundaries.” A simple fix might be to change the word
“of” to “that” so that it reads “Procedures for confirming with [someone] that new [things] are within a Balancing Authority Area’s
metered boundaries.”.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Since the requirements currently exist in BAL-005 and were not eliminated as part of P81, there is no debate that they are reliability
based. The Drafting Team is proposing relocating them to FAC-001. Unfortunately, the TOP-003-3 data specification would not serve to
confirm that a Facility is within the metered boundary of a BAA. Those data specifications are established to truly operate in real-time.
The determination that a Facility is within the metered boundaries of a BAA must be determined prior to a new Facility operating.
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It is GTC’s desire that the drafting team utilizes the justification provided by GTC to not move forward with the proposed R3.3 and R3.4
and a refer to TOP-003-3 to demonstrate that there is currently not a reliability gap and also take the time to clarify the purpose
statement to resolve the ambiguity introduced with this revision which should not prevent the drafting teams goal of an approved ballot.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator Owners
must document and make Facility interconnection study requirements available so that entities seeking to interconnect will provide the
information necessary for studies conducted in accordance with FAC-002-2.
Therefore, GTC respectfully requests this drafting team to remove R3.3 and R4.3 as a proposed change to FAC-001-2 and further clarify
the purpose statement of FAC-001 to resolve the ambiguity that this current draft introduced by clarifying the purpose of FAC-001 which
should align with FAC-002 by inserting the term “study” within the purpose statement such as:
In summary, GTC believes that the proposed requirements FAC-001-3-R3.3 and FAC-001-3-R4.3 address specific needs for operating the
system and therefore belong in an Operations Standard which is already being covered in requirements of FERC approved TOP-003-3
which describes the information that TOs and GOs are required to provide to the Balancing Authority as specified by the Balancing
Authority.
Based on the Ballot supporting material, the proposed FAC-001 R3.3 and R3.4 requirements were originally included in BAL-005-1. The
goal of the requirement in BAL-005-1 was to ensure that Area Control Error is calculated properly. Although GTC sees a merit in ensuring
that the Area Control Error is calculated properly, GTC believes that the proposed requirements (FAC-001-3-R3.3, R4.3) would violate
paragraph 81 criteria and introduces ambiguity associated with the aforementioned planning horizon vs operations horizon concerns that
is currently not addressed in FAC-001 or FAC-002. GTC believes this concern is already covered in operation horizon standards such as
TOP-003-3 and IRO-010-2. Specifically, R4 of TOP-003-3 already addresses and requires the BA to distribute its data specification to
entities that have data required by the BA analysis functions and Real-time monitoring. Additionally, R5 of TOP-003-3 requires each TOP,
GO, GOP, TO, LSE, and DP to satisfy the obligations of the documented specifications.
All of the requirements of FAC-001 are limited to the long-term planning time horizon. Based on the rationale and proposed language
provided for R3.3 and R4.3, a new level of ambiguity has presented itself that could lead some to conclude that these interconnection
requirements should be expanded beyond the planning horizon and lead up to “commissioning of a Facility” which resides in the
operations horizon.
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We do not support the proposed changes to R3 and R4. The SDT, in the rationale boxes stated “It is the responsibility of the party
interconnecting to make appropriate arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered
boundaries”. We do not believe it is appropriate to shift the compliance responsibility of one entity to another and therefore suggests
the SDT also include Distribution Provider in the applicability section and then develop a requirement to read “Entity seeking to
interconnect (TO, GO or DP) shall confirm with those responsible for the reliability of affected systems that its newly installed or modified
Facility is within a Balancing Authority Area’s metered boundaries”
The added requirements 3.3 and 4.3 are not clear. The drafting team copied R3.2 approach but it not work for 3.3. In R3.2 the
Transmision Owner is notifying the other reliability entities that new or modified interconnection is being pursued. Technically that
would include a notice to the BA. But an explicit sub-requirement is needed. Concerns with R3.3 are: 1. Use of word confirming.
Confirming is beyond notification; a confirmation requires the TO to maintain the response from the BA and possibly go further and verify
the BA is truthful. The SDT reply to the last comments indicated it was really concerned that the BA would not be aware of changes made
by TO. 2. The use of phrase “those responsible for the reliability of affected systems” is not needed and should be replaced with
‘responsible Balancing Authority’ since that is the only reliability function implicated by this subrequirement. 3.The BA should be required
to provide the procedure for notification from a TO when a new or modified interconnesction is being pursued. Then the TO can align its
Interconnection requirements document to the BA process.
Comment
Document Name
Answer
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7 - NPCC, Group Name RSC no UI O&R
Dislikes
Likes
Although the determination that a Facility is within a BAA serves real-time operations, that does not preclude the confirmation of it
occurring early than at that time. For example, Seasonal Studies are conducted to assure that proper planning occurs to allow for realtime operations. This confirmation of which BAA will have the Facility within its boundaries occurring during the planning and studying
stage is appropriate too since reconciliation of concerns may need to be addressed with this entity.
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PJM views FAC-001 as a reporting requirement that must be carefully drafted. The requirement must be crafted as an obligation that an
owner incurs “when circumstances change.” The obligation may be better addressed in a venue other than the reliability standards. One
possibility would be to include the essence of the requirement as part of the NERC registration process to avoid unnecessary compliance
tracking.
Comment
Document Name
Answer
William Temple - William Temple
Dislikes
Likes
The SDT considered the option of placing the requirement in FAC-002 but found it more appropriate to transfer this knowledge during
the interconnection process.
A Balancing Authority is not capable of knowing who should be requesting to be within its metered boundaries. However, the
transmission owner must know and Facilities to which it is connected must have an Interconnection Agreement that identifies which
Balancing Authority Area the connecting Facility is within. And, the Transmission Owner is responsible for notifying the Balancing
Authority about the Agreement. This notification is essential for reliability reasons and system control considerations.
Alternatively the proposed R3.3 and R4.3 could be moved to FAC-002-2. FAC-002-2 is more
appropriate than FAC-001-2 for this
requirement because FAC-002-2 applies to TOs and GOs “seeking to interconnect” new or modified facilities. Therefore FAC-002-2 is
more in line with the SDT’s rationale that “It is the responsibility of the party interconnecting to make appropriate arrangements
with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries…”
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area
is included within its metered boundaries.”
Requirement 3.3 and 4.3 should not be moved to FAC-001-3. The BA is in the best position to know its metered boundaries and confirm
if any new or modified transmission or generation project is within those metered boundaries. The proposed R3.3 and R4.3 should
remain in BAL-005, but be assigned to the BA. R1 from BAL-005-0.2b should be retained and re-written as follows:
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The asset owner is responsible for confirming that the party interconnecting has made appropriate provisions with a Balancing Authority
to operate within its metered boundaries.
FAC-001-3. NYPA has a concern that R3.3 and 4.3 should be the responsibility of the interconnecting entity to ensure their facility is
within a BA’s metered boundary.
Comment
Document Name
Answer
Shivaz Chopra - New York Power Authority - 6
Dislikes
Likes
The idea of NERC having a registry is not without merit, but is outside the scope of this Drafting Team.
It is a proven reliability risk that all Facilities must be within the metered boundaries of a BAA. If not, a Facility such as a generator could
harm Frequency without any consequence. Although the implementation of confirming any new and modified facilities (not all existing
equipment, as is mentioned in the comment) will take on an administrative nature, that does not diminish its importance in ensuring
reliability because it provides added assurance that all facilities are taken into account in planning.
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that predates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary
to explicitly state that all facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper
exchange where TOPs, GOPs, and Loads will be asking BAs for pieces of documentation that they are within a given BA or to sign
agreements that acknowledge the facility is within a BA. Keep in mind this includes each and every load, every piece of transmission, and
every generator. This provides no reliability value.
Every facility owner is required to register with NERC. PJM proposes that as part of that process, the facility owners identify the RC area,
BA area and TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas
change, then the owner must inform NERC of the change and also inform the entity(ies) that are involved.
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Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
John Fontenot - Bryan Texas Utilities - 1
Dislikes
Likes
The SDT agrees with your concern, but this consideration is addressed in the purpose of the requirement. The purpose of the
requirement is to be certain that the entity has joined a BAA, regardless of the number of options available to them. Just because they
can only join one BAA, does not mean that they did. As such, the SDT does not believe this conforming modification is necessary.
4.3 In regions with multiple Balancing Authorities, Procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified generation Facilities are within a Balancing Authority Area’s metered boundaries.
Recommend the standard language additions:
3.3 In regions with multiple Balancing Authorities, procedures for confirming with those responsible for the reliability of affected
systems of new or materially modified transmission Facilities are within a Balancing Authority Area’s metered boundaries.
The SDT should consider the impact of new requirements R3.3 and R4.3 in regions where a single BA exists. These requirements would
not seem to apply in cases such as ERCOT, where clearly any TO or GO facility additions are within the one and only BA’s metered
boundaries.
Comment
Document Name
Answer
Dixie Wells - Lower Colorado River Authority - 5, Group Name LCRA Compliance
Dislikes
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0
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Also, Duke Energy suggests a minor modification to language used in the sub-requirements of R3 and R4. We suggest the use of the term
Procedure[s] with the [s] accompanying. This clears up ambiguity that could arise in the event that an entity only has one procedure that
is applicable to these requirements.
We feel that these modifications and the resulting modifications to the Guidelines and Technical Basis section of the standard, better
illustrates the intent of the drafting team, without needing the requirements’ rationale to decipher said intent.
R4.3: Procedures for confirming that new or materially modified generation Facilities are accurately telemetered, modeled, and accounted
in Real-time systems of the Balancing Authority(s) designated by the interconnecting entity.
R3.3: Procedures for confirming that new or materially modified transmission Facilities are accurately telemetered, modeled, and
accounted in Real-time systems of the Balancing Authority(s) designated by the interconnecting entity.
Duke Energy is not certain that the current language in R3.3 and R4.3 of the proposed FAC-001-3 adequately establishes that it is the
responsibility of the interconnecting entity to make the necessary arrangements, and that the Transmission Owner is responsible for
confirming with a Generator, who their Balancing Authority will be. We feel that this intent is clear from reading the Rationale for R3, but
do not feel that this intent is ascertainable by reading R3.3 on its own. Duke Energy suggests the following revisions to R3.3 and R4.3 to
add clarity:
Comment
Document Name
Answer
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RFC, Group Name Duke Energy
Dislikes
Likes
na
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R3.3
R4.3 – Procedures for confirming with the associated Balancing Authority that the new or materially modified generation and/or
transmission Facilities, that those generation and/or transmission Facilities are within its metered boundaries.
R3.3 – Procedures for confirming with the associated Balancing Authority that the new or materially modified generation and/or
transmission Facilities, that those generation and/or transmission Facilities are within its metered boundaries.
75
APS agrees with the approach for Requirements R3.3 and R4.3, in that it is the responsibility of the party interconnecting to make
appropriate arrangements with a Balancing Authority, and that the Transmission Owner or Generation Owner is responsible for
confirming that the party interconnecting to make appropriate arrangements with a Balancing Authority. Since Transmission Owners and
Generation Owners may receive either transmission or generation interconnection requests, APS recommends revising the requirements
as follows:
Comment
Document Name
Answer
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Dislikes
Likes
But the Drafting Team believes it is not reasonable or appropriate for the TO or applicable GO to assess how the BAA has incorporated
“accurately” the entity into their BAA systems. Since all BAAs are certified, we can assume if the entity has an agreement for them to be
in their BAA, that BAA has the ability to incorporate them into their systems appropriately.
The SDT contends that this not be limited to one and only one BA and the SDT recognizes that multiple BAs may be involved.
The Drafting Team appreciates the feedback. The SDT recognizes that this is an issue in all NERC Reliability Standards. The Alignment of
Terms SDT will be addressing this issue. For additional information please refer to Arizona Public Service comments and our associated
response on pages 75 and 76 of this report.
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January 28, 2016
Answer
Anthony Jablonski - ReliabilityFirst - 10
Dislikes
Likes
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The drafting team has made conforming modifications to Requirement R4.3 to accurately reflect the intent of the drafting team, as
described in the Rationale for R4.3. As stated in the Rationale, “it is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries, which also serves to facilitate the
process of the coordination between the two entities that will be required under numerous other standards upon the start of operation.”
Additionally, the “Generator Owner is responsible for confirming that the party interconnecting has made appropriate provisions with a
Balancing Authority to operate within its metered boundaries.” By removing the term “generation,” Requirement R4.3 more clearly
reflects the fact that a Generator Owner properly addresses procedures for confirming that those responsible for reliability of the
applicable affected systems are within a Balancing Authority Area’s metered boundaries. This change promotes reliability because it
ensures confirmation that all entities that affect reliability share relevant information because they are within a Balancing Authority
Area’s metered boundaries.
R4.3
The drafting team has made conforming modifications to Requirement R3.3 to accurately reflect the intent of the drafting team, as
described in the Rationale for R3.3. As stated in the Rationale, “it is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered boundaries, which also serves to facilitate the
process of the coordination between the two entities that will be required under numerous other standards upon the start of operation.”
Additionally, the “Transmission Owner is responsible for confirming that the party interconnecting has made appropriate provisions with
a Balancing Authority to operate within its metered boundaries.” By removing the term “transmission,” Requirement R3.3 more clearly
reflects the fact that a Transmission Owner properly addresses procedures for confirming that those responsible for reliability of the
applicable affected systems are within a Balancing Authority Area’s metered boundaries. This change promotes reliability because it
ensures confirmation that all entities that affect reliability share relevant information because they are within a Balancing Authority
Area’s metered boundaries.
Part 3.3 uses the term “materially modified”. RF believes this term is ambiguous and requests the SDT further clarify
what is considered a “materially modified transmission Facility”.
i.
Part 4.3 uses the term “materially modified”. RF believes this term is ambiguous and requests the SDT further clarify
what is considered a “materially modified generation Facility”.
Requirement 4, Part 4.3
i.
Requirement 3, Part 3.3
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2. Do requirements R3.2 and R3.3 means the TO must perform this confirmation or can the procedure require the interconnecting party
perform the confirmation? UI believes the TO establishes the procedure, or writes into its interconnection document the BA's process,
77
1. R3.2 has the TO establishing a procedure to provide a notification whle R3.3 requires a confirmation. What is the difference in actions
between notification and confirmation? Who or what is to be confirmed? The technical and guideline section should explain what the
confirmation is supposed to be.
Comment
Document Name
Answer
Jonathan Appelbaum - United Illuminating Co. - 1
Dislikes
Likes
“Materially modified” was used in Requirement R3.1, R3.2, R4.1, and R4.2 of the current standard and the SDT used the same language
for consistency and felt since it was previously approved we believe that it is clear, from experience, that the industry understands the
meaning.
2.
1.
ReliabilityFirst agrees the draft FAC-001-3 draft standard but offers the following comments for consideration.
Comment
Document Name
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Douglas Webb - Douglas Webb
Dislikes
Likes
78
Thank you for your language suggestions. The SDT has modified the requirement for clarity. The Drafting Team does not prescribe how
the applicable entity would draft their procedure[s] to accomplish the objective of confirming a BAA exists for the Facility. Each entity
can decide how the outcome is achieved.
The purpose of confirmation is to be certain that the information associated with the Facility has been transferred to the appropriate BA.
The TO or applicable GO would not know who to “notify” until they have confirmed there is a BAA to notify.
4. If proposed R3.3 was to be approved then it is missing the word "that". It should state: "Procedures for confirming with those
responsible for the reliability of affected systems that new or materially modified transmission Facilities are within a Balancing Authority
Area’s metered boundaries.."
"R3.2 requires the TO to establish a procedure to notify those responsible for the reliability of affected system(s) of new or materially
modified existing interconnections. Notification means that the TO, requires either itself or the interconnecting party to contact the
relevant reliability authorities and provide notice of the facility. R3.3 requires the TO to establish a procedure to confirm that a facility is
within a metered boundary of a BA. Confirmation means that the TO, requires either itself or the interconnecting party to contact the BA
and receive a letter of confirmation that the facility is in the BA metered boundary. The requirement and measure for R3 is only that the
processes are established in the requirements document. The requirements document may reference a market or tariff as its process."
This is my proposed addition to Techincal Guideline section to address my comments 1 to 3:
3. What is the purpose of R3.3 requiring a confrimation with " those responsible for the reliability of affected systems" instead of just
stating the Balancing Authority. It should be the BA.
but the requirements document can require the interconnecting party to perform the notifiction and confirmation. If so, this should be
added to the Technical Guideline section of Standard.
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
79
Generally, defined terms better serve compliance with Standards and implementation of Requirements. The term, "affected system" is
not defined. FERC approved pro forma interconnection agreements define the term as, "…an electric system other than the Transmission
Provider's Transmission System that may be affected by the proposed interconnection." KCP&L believes there may be benefit aligning the
"Affected System"
R3.3: "Procedures for confirming with those responsible for the reliability of affected systems of new or materially modified transmission
Facilities are within a Balancing Authority Area’s metered boundaries."
KCP&L recommends removing R3.3 or, in the alternative, suggests deleting "with those responsible for the reliability of affected systems
of" from the proposed R3.3.
To achieve the stated rationale’s goal, It would seem the compliance duty should fall to the party interconnecting. Absent that, the
Balancing Authority and/or the Generator Owner whose facilities are used to interconnect to the transmission system would be in a
better position to address Balancing Authority Area’s metered boundaries. Also, the Requirement seems redundant since there are active
NERC Standards requiring Generator Owners to inform Transmission Owners of changes to the GOs’ facilities and Transmission Owners
informing BA of new interconnections. Finally, from a practical viewpoint, it is just not likely a PI would connect without metering and
SCADA connections—all such activity providing visibility to the BA and TO of changes to the system.
The difficulty with R3.3, as proposed, is evident when compliance scenarios are considered. For example, the Transmission Owner creates
the required procedure under R3.3. The rationale—the compliance goal—for R3.3 centers on a duty by of the party interconnecting (PI)
to make appropriate arrangements with the BA to ensure the PI Facilities are within the BA’s metered boundaries. If the PI fails to fulfill
its duty, it raises the question: Where is the noncompliance under R3.3? The Transmission Owner created the procedure, as required, yet,
the stated rationale, goal, is not accomplished.
R3.3 creates a compliance obligation for a disinterested party. The proposed R3.3, in effect, requires the Transmission Owner to create a
procedure to promote the exchange of information between a third party Facility interconnecting with a Generator Owner whose facility
is used to connect to the Transmission system. The procedure developed by the Transmission Owner must identify "affected systems,"
confirm who is responsible for reliability of the "affected systems," and, confirm with the "affected systems" owner that new
interconnected facilities are within the metered boundaries of the identified Balancing Authority.
Requirement 3.3
KCP&L does not support the proposed revisions to FAC-001-3 R3.3 and recommends not adopting the Requirement. The proposed
revised Standard is applicable to KCP&L as a registered Transmission Owner and, potentially, as a registered Generator Owner.
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that predates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary
to explicitly state that all facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper
exchange where TOPs, GOPs, and Loads will be asking BAs for pieces of documentation that they are within a given BA or to sign
80
Every facility own should be required to register with NERC. The SRC proposes that as part of that process the owners identify the RC area,
BA area and TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas
change, then the owner must inform NERC of the change and also inform the entitiy(ies) that will be changed.
The SRC views FAC-001 as a reporting requirement that must be carfully drafted. The requirement must be crafted as an obligation that
an owner incurs “when circumstances change”. The obligation may be better addressed in a venue other than the reliability standards.
One possibility would be to include the essence of the requirmentas part of the NERC registration process to avoid unnecessary compliance
tracking.
ERCOT supports the comments of the IRC SRC. The comments are provided below:
Comment
Document Name
Answer
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Dislikes
Likes
The asset owner is responsible for confirming that the party interconnecting has made appropriate provisions with a Balancing Authority
to operate within its metered boundaries.
The SDT believes that the lack of confirmation would indicate their procedure inadequate.
undefined NERC Standard terms relating to interconnection facilities with equivalent FERC pro forma interconnection agreements defined
terms. While such an effort would require substantial effort to address all affected Standards, for the purposes of this Standard, we
would encourage adopting FERC’s pro forma definition for the proposed revision to FAC-001-3.
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Document Name
Answer
Chris Scanlon - Exelon - 1, Group Name Exelon Utilities
Dislikes
Likes
The SDT disagrees that confirming all Facilities are within a BAA metered boundary does not improve the reliability of the system. An
example of how this could negatively impact reliability is when a generator that has not transferred the knowledge that it is within a BA
and thus may have an impact on control and Frequency.
This standard should not be a reliability standard, the contents of the standard do nothing to improve the reliability of the system.
Comment
Document Name
Answer
Joshua Eason - ISO New England, Inc. - NA - Not Applicable - NPCC
Dislikes
Likes
The idea of NERC having a registry is not without merit, but is outside the scope of this Drafting Team.
It is a proven reliability risk that all Facilities must be within the metered boundaries of a BAA. If not, a Facility such as a generator could
harm Frequency without any consequence. Although the implementation of confirming any new and modified facilities (not all existing
equipment, as is mentioned in the comment) will take on an administrative nature, that does not diminish its importance in ensuring
reliability because it provides added assurance that all facilities are taken into account in planning.
81
agreements that acknowledge the facility is within a BA. Keep in mind this includes each and every load, every piece of transmission, and
every generator. This provides no reliability value.
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Comment
Document Name
Answer
Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC, Group Name ISO Standards Review Committee
Dislikes
Likes
“Materially modified” was used in Requirement R3.1, R3.2, R4.1, and R4.2 of the current standard and the SDT used the same language
for consistency and felt since it was previously approved we believe that it is clear, from experience, that the industry understands the
meaning.
82
We also note that the phrase "materilaly modifed" may be subject to interpretation during an audit. The Guideline and Technical Basis
section allows the use of engineering judgement when determing what is "material". It seems to beg the question, if an entity is using it's
interconnection process and associated procedures as required by the Standrd, the change is material. Has the SDT considerd removing
material from the language? This phrase is not defined or used in any other standard other than FAC-001 and 002. We believe either of
these changes are non-substantive and would not require an additional comment period.
3.3. Procedures for confirming with responsible entities that that the new or modified Facilities are within a Balancing Authority Area’s
metered boundaries.
3.2. Procedures for notifying responsible entities of affected systems identified in part 3.1.
3.1. Procedures for coordinated studies of new or materially modified interconnections and impacts on affected system(s).
R3. Each Transmission Owner shall address the following items in its Facility interconnection requirements for new or materially modified
existing interconnections:
Exelon thinks R3 (and R4) needs to be re-written. We suggest:
Comment
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Requirement 3.3 and 4.3 should not be moved to FAC-001-3. The BA is in the best position to know its metered boundaries and confirm
if any new or modified transmission or generation project is within those metered boundaries. The proposed R3.3 and R4.3 should
remain in BAL-005, but be assigned to the BA. R1 from BAL-005-0.2b should be retained and re-written as follows:
Comment
Document Name
Answer
Kelly Dash - Kelly Dash, Group Name Con Edison
Dislikes
Likes
“Materially modified” was used in Requirement R3.1, R3.2, R4.1, and R4.2 of the current standard and the SDT used the same language
for consistency and felt since it was previously approved we believe that it is clear, from experience, that the industry understands the
meaning.
83
The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria that predates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and unnecessary
to explicitly state that all facilities must be within a BA. A FAC-001-3 requirement to have verification of this will just lead to a paper
exchange where TOPs, GOPs, and Loads will be asking BAs for pieces of documentation that they are within a given BA or to sign
agreements that acknowledge the facility is within a BA. Keep in mind this includes each and every load, every piece of transmission, and
every generator. This provides no reliability value.
Every facility own should be required to register with NERC. The SRC proposes that as part of that process the owners identify the RC area,
BA area and TOP area that the facility will operate within. The registration would also mandate that whenever one or more of those areas
change, then the owner must inform NERC of the change and also inform the entitiy(ies) that will be changed.
The SRC views FAC-001 as a reporting requirement that must be carfully drafted. The requirement must be crafted as an obligation that
an owner incurs “when circumstances change”. The obligation may be better addressed in a venue other than the reliability standards.
One possibility would be to include the essence of the requirmentas part of the NERC registration process to avoid unnecessary compliance
tracking.
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Jeremy Voll - Basin Electric Power Cooperative - 3
Dislikes
Likes
Thank you for your comment. Please refer to our responses to the entities mentioned above.
this needs work & here my support for the overall theme of comments submitted by MRO-NSRF, SCR, and also Oncor.
Comment
Document Name
Answer
Glenn Pressler - CPS Energy - 1,3,5
Dislikes
Likes
84
The Interconnecting Party decides which BAA they are going to be within, not the BAA. A Balancing Authority is not capable of knowing
who should be requesting to be within its metered boundaries, nor can they require someone to be inside their BAA. For reliability
reasons, we must confirm they have transferred the knowledge to at least one BA. The Drafting Team believes this confirmation
occurring as part of the Interconnection process is more appropriate than when the studies are occurring in FAC-002. The asset owner is
responsible for confirming that the party interconnecting has made appropriate provisions with a Balancing Authority to operate within
its metered boundaries.
Alternatively the proposed R3.3 and R4.3 could be moved to FAC-002-2. FAC-002-2 is more appropriate than FAC-001-2 for this
requirement because FAC-002-2 applies to TOs and GOs “seeking to interconnect” new or modified facilities. Therefore FAC-002-2 is
more in line with the SDT’s rationale that “It is the responsibility of the party interconnecting to make appropriate arrangements with a
Balancing Authority to ensure its Facilities are within the BA’s metered boundaries…”
“The Balancing Authority shall ensure that any new or modified generation or transmission operating within its Balancing Authority Area
is included within its metered boundaries.”
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
85
R3.3 and R4.3 The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area criteria
that pre-dates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant and
unnecessary to explicitly state that all facilities must be within a BA. The FAC-001-2 requirement to have verification of this will just lead
to a paper exchange where TO, GO, will be asking BAs for pieces of documentation that they are within a given BA or to sign agreements
that acknowledge the facility is within a BA. This provides no incremental reliability value. Recommend to remove this Requirement.
Comment
Document Name
Answer
Emily Rousseau - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Dislikes
Likes
The Drafting Team disagrees that confirming all Facilities are within a BAA metered boundary does not improve the reliability of the
system. It is a proven reliability risk that all Facilities must be within the metered boundaries of a BAA. If not, a Facility such as a
generator could harm Frequency without any consequence. Although the implementation of confirming any new and modified facilities
(not all existing equipment, as is mentioned in the comment) will take on an administrative nature, that does not diminish its importance
in ensuring reliability because it provides added assurance that all facilities are taken into account in planning.
R3.3 and R4.3: The concept that all generation, transmission, and load must be within the metered bounds of a BA is a control area
criteria that pre-dates the NERC standards. It is a concept that comes about by operating to common meters. It is therefore redundant
and unnecessary to explicitly state that all facilities must be within a BA. The FAC-001-2 requirement to have verification of this will just
lead to a paper exchange where TO, GO, will be asking BAs for pieces of documentation that they are within a given BA or to sign
agreements that acknowledge the facility is within a BA. This provides no incremental reliability value. Recommend to remove this
Requirement.
Comment
Document Name
Answer
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
Oncor does not support the proposed changes to R3. The SDT, in the rationale box states “the Transmission Owner is responsibile for
confirming that the party interconnecting has made appropriate provisions with a Balancing Authority to operate within its metered
Comment
Document Name
Answer
Tammy Porter - Tammy Porter
Dislikes
Likes
Thank you.
SRP is in support of the proposed FAC-001-3
Comment
Document Name
Answer
Diana McMahon - Salt River Project - 1,3,5,6 - WECC
Dislikes
Likes
86
The Drafting Team disagrees that confirming all Facilities are within a BAA metered boundary does not improve the reliability of the
system. It is a proven reliability risk that all Facilities must be within the metered boundaries of a BAA. If not, a Facility such as a
generator could harm Frequency without any consequence. Although the implementation of confirming any new and modified facilities
(not all existing equipment, as is mentioned in the comment) will take on an administrative nature, that does not diminish its importance
in ensuring reliability because it provides added assurance that all facilities are taken into account in planning.
0
0
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
87
Dominion does not support the proposed changes to R3 and R4. The SDT, in the rationale boxes stated “It is the responsibility of the party
interconnecting to make appropriate arrangements with a Balancing Authority to ensure its Facilities are within the BA’s metered
boundaries”. Dominion does not believe it is appropriate to shift the compliance responsibility of one entity to another and therefore
suggests the SDT also include Distribution Provider in the applicability section and then develop a requirement to read “Entity seeking to
Comment
Document Name
Answer
Louis Slade - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Dislikes
Likes
Provided in ACES Comments
Comment
Document Name
Answer
William Hutchison - Southern Illinois Power Cooperative - 1
Dislikes
Likes
The asset owner is responsible for confirming that the party interconnecting has made appropriate provisions with a Balancing Authority
to operate within its metered boundaries.
boundaries”. Oncor does not believe that the Transmission Owner should be responsible for the compliance of the interconnecting
Transmission Owner. Therefore, Oncor recommends changing R3.3 to the following: "3.3. Requirement that new or materially modified
transmission Facilities of the interconnecting Transmission Owner are within a Balancing Authority Area's metered boundaries."
0
0
Consideration of Comments | Project 2010-14.2.1 Phase 2 of BARC | BAL-005-1, BAL-006-2, FAC-001-3
January 28, 2016
End of Report
Dislikes
Likes
88
The asset owner is responsible for confirming that the party interconnecting has made appropriate provisions with a Balancing Authority
to operate within its metered boundaries.
interconnect (TO, GO or DP) shall confirm with those responsible for the reliability of affected systems that its newly installed or modified
Facility is within a Balancing Authority Area’s metered boundaries”
Standards Announcement Reminder
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Additional Ballots and Non-binding Polls Open through January 11, 2016
Now Available
Additional ballots for BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility Interconnection
Requirements, and the recommended retirement of BAL-006-2 – Inadvertent Interchange as well as
non-binding polls of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) for
BAL-005-1 and FAC-001-3 are open through 8 p.m. Eastern, Monday, January 11, 2016.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in these drafts of the standards.
Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the
standards and associated VRFs and VSLs by clicking here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
The results will be announced and posted to the project page when the ballots close. The drafting team
will consider all comments received during the formal comment period and determine the next steps of
the project.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Formal Comment Period Open through January 11, 2016
Now Available
A formal comment period for BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility
Interconnection Requirements, and the recommended retirement of BAL-006-2 – Inadvertent
Interchange is open through 8 p.m. Eastern, Monday, January 11, 201.
The standard drafting team’s considerations of the responses received from the last comment period
are reflected in these drafts of the standards.
Commenting
Use the electronic form to submit comments on the standards. If you experience any difficulties in
using the electronic form, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
If you are having difficulty accessing the Standards Balloting & Commenting System due to a
forgotten password, incorrect credential error messages, or system lock-out, contact NERC IT support
directly at [email protected] (Monday – Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
An additional ballot for the three standards and a non-binding poll of the associated Violation Risk
Factors and Violation Severity Levels for FAC-001-3 will be conducted December 31, 2015 through
January 11, 2016.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Ballot and Non-binding Poll Results
Now Available
A formal comment period and additional ballots for BAL-005-1 –Balancing Authority Control and FAC001-3 – Facility Interconnection Requirements, a ballot for the recommended retirement of BAL-006-2 –
Inadvertent Interchange, as well as a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels for BAL-005-1 and FAC-001-3 concluded 8 p.m. Eastern, Monday, January 11,
2016.
The standards received sufficient affirmative votes for approval. Voting statistics are listed below, and the
Ballot Results page provides detailed results for the ballots and non-binding polls.
Ballot
Non-binding Poll
Standard
Quorum / Approval
Quorum / Supportive Opinions
BAL-005-1
84.13% / 70.64%
82.53% / 74.38%
FAC-001-3
83.17% / 75.54%
82.53% / 75.44%
BAL-006-2
84.44% / 94.30%
Next Steps
The drafting team will consider all comments received during the formal comment period and determine
the next steps of the project.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Surveys
Legacy SBS (https://standards.nerc.net/)
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/38)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1 IN 1 ST
Voting Start Date: 12/31/2015 12:01:00 AM
Voting End Date: 1/11/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 265
Total Ballot Pool: 315
Quorum: 84.13
Weighted Segment Value: 70.64
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
78
1
43
0.741
15
0.259
0
8
12
Segment:
2
10
0.9
4
0.4
5
0.5
0
0
1
Segment:
3
72
1
42
0.792
11
0.208
0
8
11
Segment:
4
25
1
16
0.889
2
0.111
0
2
5
Segment:
5
72
1
32
0.696
14
0.304
0
12
14
Segment:
6
44
1
24
0.727
9
0.273
1
5
5
Segment:
7
2
0
0
0
0
0
0
0
2
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment: 2
0.1
1
0.1
8
© 2016 - NERC Ver 3.0.0.0 Machine Name: ERODVSBSWB01
Segment: 2
0.2
1
0.1
9
Segment:
10
8
0.8
5
0.5
3
0.3
0
0
0
Totals:
315
7
168
4.945
60
2.055
1
36
50
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Third-Party
Comments
1
Black Hills
Corporation
Wes Wingen
Abstain
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Negative
Comments
Submitted
1
Dairyland Power
Cooperative
Robert Roddy
Negative
Third-Party
Comments
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Abstain
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Abstain
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Affirmative
N/A
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Negative
Third-Party
Louis Guidry
Douglas Webb
Comments
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
None
N/A
Abstain
N/A
Nicolas Turcotte
Negative
Comments
Submitted
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Third-Party
Comments
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power
Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public
Power District
Jamison Cawley
Negative
Third-Party
Comments
1
New York Power
Authority
Salvatore Spagnolo
Negative
Comments
Submitted
Oshani
Pathirane
Scott Miller
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern
Indiana Public
Service Co.
Charles Raney
Negative
Third-Party
Comments
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Negative
Comments
Submitted
1
Oncor Electric
Delivery
Rod Kinard
Affirmative
N/A
1
OTP - Otter Tail
Power Company
Charles Wicklund
Negative
Third-Party
Comments
1
Peak Reliability
Jared Shakespeare
None
N/A
1
PHI - Potomac
Electric Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
None
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
Tammy Porter
1
Sacramento
Municipal Utility
District
Tim Kelley
1
Salt River Project
1
Joe Tarantino
Affirmative
N/A
Steven Cobb
Affirmative
N/A
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
Third-Party
Comments
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
Comments
Submitted
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent
Electricity System
Operator
Leonard Kula
Negative
Comments
Submitted
2
ISO New England,
Inc.
Michael Puscas
Negative
Comments
Submitted
2
Midcontinent ISO,
Inc.
Terry BIlke
Negative
Third-Party
Comments
2
New York
Independent System
Operator
Gregory Campoli
Negative
Third-Party
Comments
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power
Pool, Inc. (RTO)
Charles Yeung
None
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Abstain
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Abstain
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
Kathleen
Goodman
William Temple
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Third-Party
Comments
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Affirmative
N/A
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Negative
Comments
Submitted
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Abstain
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Abstain
N/A
Darnez
Gresham
Bill Hughes
Louis Guidry
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Negative
Third-Party
Comments
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric
System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
Third-Party
Comments
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public
Power District
Tony Eddleman
Negative
Third-Party
Comments
3
New York Power
Authority
David Rivera
Negative
Comments
Submitted
3
NiSource - Northern
Ramon Barany
Negative
Third-Party
Douglas Webb
Oshani
Pathirane
Indiana Public
Service Co.
Comments
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Negative
Comments
Submitted
3
PHI - Potomac
Electric Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Negative
Comments
Submitted
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento
Municipal Utility
District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power
Electric Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County
Mark Oens
Affirmative
N/A
Joe Tarantino
PUD No. 1
3
Southern Company Alabama Power
Company
R. Scott Moore
Affirmative
N/A
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
None
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Negative
Third-Party
Comments
4
Austin Energy
Tina Garvey
Abstain
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
None
N/A
Bill Hughes
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Abstain
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Affirmative
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Negative
Third-Party
Comments
4
Modesto Irrigation
District
Spencer Tacke
None
N/A
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
Joe Tarantino
4
Utility Services, Inc.
Brian Evans-Mongeon
None
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Abstain
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Abstain
N/A
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Third-Party
Comments
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of
San Francisco
Daniel Mason
Abstain
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy -
David Greyerbiehl
None
N/A
Consumers Energy
Company
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Negative
Comments
Submitted
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Abstain
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Abstain
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Abstain
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power
and Light Co.
Harold Wyble
Affirmative
N/A
5
Great River Energy
Preston Walsh
Negative
Third-Party
Comments
5
Hydro-Qu?bec
Production
Roger Dufresne
Negative
Third-Party
Comments
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Abstain
N/A
Kelly Dash
Douglas Webb
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Affirmative
N/A
5
Lower Colorado River
Authority
Dixie Wells
Abstain
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Negative
Third-Party
Comments
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Third-Party
Comments
5
NB Power
Corporation
Rob Vance
Negative
Third-Party
Comments
5
Nebraska Public
Power District
Don Schmit
Negative
Third-Party
Comments
5
New York Power
Authority
Wayne Sipperly
Negative
Comments
Submitted
5
NextEra Energy
Allen Schriver
Negative
Third-Party
Comments
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Negative
Comments
Submitted
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail
Power Company
Cathy Fogale
Negative
Third-Party
Comments
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
Scott Miller
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation,
LLC
Donald Lock
Abstain
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa
Electric Co.
R James Rocha
None
N/A
5
Tennessee Valley
Brandy Spraker
Negative
Comments
Joe Tarantino
Authority
Submitted
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Abstain
N/A
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Abstain
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Abstain
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Abstain
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power
Chris Bridges
Douglas Webb
Affirmative
N/A
and Light Co.
6
Great River Energy
Donna Stephenson
6
Lower Colorado River
Authority
6
Michael
Brytowski
Negative
Third-Party
Comments
Michael Shaw
None
N/A
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
Third-Party
Comments
6
New York Power
Authority
Shivaz Chopra
Negative
Comments
Submitted
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Third-Party
Comments
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Negative
Comments
Submitted
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
No
Comment
Submitted
6
Platte River Power
Authority
Carol Ballantine
Affirmative
N/A
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Negative
Comments
Submitted
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
Nick Braden
Joe Tarantino
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa
Electric Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Negative
Comments
Submitted
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Attorney General
Frederick Plett
Affirmative
N/A
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Negative
Third-Party
Comments
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
Third-Party
Comments
Amy Casuscelli
10
Northeast Power
Coordinating Council
Guy V. Zito
Negative
Comments
Submitted
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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1
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BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/38)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-006-2 IN 1 ST
Voting Start Date: 12/31/2015 12:01:00 AM
Voting End Date: 1/11/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 266
Total Ballot Pool: 315
Quorum: 84.44
Weighted Segment Value: 94.3
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
78
1
55
0.965
2
0.035
0
9
12
Segment:
2
10
1
8
0.8
2
0.2
0
0
0
Segment:
3
72
1
52
0.981
1
0.019
0
8
11
Segment:
4
25
1
16
1
0
0
0
4
5
Segment:
5
72
1
46
0.979
1
0.021
0
11
14
Segment:
6
44
1
32
0.97
1
0.03
1
5
5
Segment:
7
2
0
0
0
0
0
0
0
2
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment: 2
0.1
1
0.1
8
© 2016 - NERC Ver 3.0.0.0 Machine Name: ERODVSBSWB02
Segment: 2
0.2
1
0.1
9
Segment:
10
8
0.8
8
0.8
0
0
0
0
0
Totals:
315
7.1
219
6.695
8
0.405
1
38
49
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Affirmative
N/A
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Affirmative
N/A
1
Black Hills
Corporation
Wes Wingen
Abstain
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Affirmative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Affirmative
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Abstain
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Abstain
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Affirmative
N/A
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
Louis Guidry
Douglas Webb
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
None
N/A
Abstain
N/A
Nicolas Turcotte
Affirmative
N/A
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Third-Party
Comments
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power
Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public
Power District
Jamison Cawley
Affirmative
N/A
1
New York Power
Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy Florida Power and
Mike ONeil
Affirmative
N/A
Oshani
Pathirane
Scott Miller
Light Co.
1
NiSource - Northern
Indiana Public
Service Co.
Charles Raney
Affirmative
N/A
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Affirmative
N/A
1
Oncor Electric
Delivery
Rod Kinard
Abstain
N/A
1
OTP - Otter Tail
Power Company
Charles Wicklund
Affirmative
N/A
1
Peak Reliability
Jared Shakespeare
None
N/A
1
PHI - Potomac
Electric Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
None
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
1
Sacramento
Tim Kelley
Affirmative
N/A
Tammy Porter
Joe Tarantino
Municipal Utility
District
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
Third-Party
Comments
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Affirmative
N/A
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent
Electricity System
Operator
Leonard Kula
Affirmative
N/A
2
ISO New England,
Inc.
Michael Puscas
Negative
Comments
Submitted
2
Midcontinent ISO,
Inc.
Terry BIlke
Affirmative
N/A
2
New York
Independent System
Operator
Gregory Campoli
Affirmative
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power
Pool, Inc. (RTO)
Charles Yeung
Negative
Third-Party
Comments
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Abstain
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Abstain
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
3
Beaches Energy
Steven Lancaster
Affirmative
N/A
Kathleen
Goodman
William Temple
Services
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
3
Bonneville Power
Administration
3
Darnez
Gresham
Affirmative
N/A
Rebecca Berdahl
Affirmative
N/A
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Affirmative
N/A
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Abstain
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Abstain
N/A
Bill Hughes
Louis Guidry
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric
System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public
Power District
Tony Eddleman
Affirmative
N/A
3
New York Power
Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
Affirmative
N/A
Douglas Webb
Oshani
Pathirane
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Affirmative
N/A
3
PHI - Potomac
Electric Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Negative
Comments
Submitted
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento
Municipal Utility
District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power
Electric Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company -
R. Scott Moore
Affirmative
N/A
Joe Tarantino
Alabama Power
Company
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
None
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Abstain
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
None
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
Bill Hughes
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Abstain
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Abstain
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Affirmative
N/A
4
Modesto Irrigation
District
Spencer Tacke
None
N/A
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Abstain
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
None
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
Joe Tarantino
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Abstain
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Abstain
N/A
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Third-Party
Comments
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of
San Francisco
Daniel Mason
Affirmative
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
None
N/A
5
Cogentrix Energy
Mike Hirst
None
N/A
Power Management,
LLC
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Affirmative
N/A
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Abstain
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Abstain
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Abstain
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power
and Light Co.
Harold Wyble
Affirmative
N/A
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Hydro-Qu?bec
Production
Roger Dufresne
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Affirmative
N/A
5
Lower Colorado River
Dixie Wells
Abstain
N/A
Kelly Dash
Douglas Webb
Authority
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Affirmative
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Affirmative
N/A
5
NB Power
Corporation
Rob Vance
Affirmative
N/A
5
Nebraska Public
Power District
Don Schmit
Affirmative
N/A
5
New York Power
Authority
Wayne Sipperly
Affirmative
N/A
5
NextEra Energy
Allen Schriver
Affirmative
N/A
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Affirmative
N/A
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail
Power Company
Cathy Fogale
Affirmative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Dan Wilson
None
N/A
Scott Miller
Corporation
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation,
LLC
Donald Lock
Abstain
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa
Electric Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
Brandy Spraker
Affirmative
N/A
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Abstain
N/A
Joe Tarantino
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Affirmative
N/A
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Abstain
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Abstain
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Abstain
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Affirmative
N/A
6
Lower Colorado River
Michael Shaw
None
N/A
Authority
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Affirmative
N/A
6
New York Power
Authority
Shivaz Chopra
Affirmative
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Affirmative
N/A
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
No
Comment
Submitted
6
Platte River Power
Authority
Carol Ballantine
Affirmative
N/A
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Negative
Comments
Submitted
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
Nick Braden
Joe Tarantino
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa
Electric Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Attorney General
Frederick Plett
Affirmative
N/A
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Negative
Third-Party
Comments
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Affirmative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
David Greene
Affirmative
N/A
Amy Casuscelli
Corporation
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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1
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BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/38)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 IN 1 ST
Voting Start Date: 12/31/2015 12:01:00 AM
Voting End Date: 1/11/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 262
Total Ballot Pool: 315
Quorum: 83.17
Weighted Segment Value: 75.54
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
78
1
44
0.721
17
0.279
0
4
13
Segment:
2
10
0.8
4
0.4
4
0.4
0
0
2
Segment:
3
72
1
45
0.763
14
0.237
0
1
12
Segment:
4
25
1
17
0.85
3
0.15
0
0
5
Segment:
5
72
1
42
0.764
13
0.236
0
3
14
Segment:
6
44
1
29
0.763
9
0.237
0
1
5
Segment:
7
2
0
0
0
0
0
0
0
2
0
0
0
1
0
0
0
0
1
0
Segment
Segment: 2
0.1
1
0.1
8
© 2016 - NERC Ver 3.0.0.0 Machine Name: ERODVSBSWB02
Segment: 2
0.1
1
0.1
9
Segment:
10
8
0.7
6
0.6
1
0.1
0
1
0
Totals:
315
6.7
189
5.061
61
1.639
0
12
53
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
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Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Third-Party
Comments
1
Black Hills
Corporation
Wes Wingen
Affirmative
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Negative
Comments
Submitted
1
Dairyland Power
Cooperative
Robert Roddy
Negative
Third-Party
Comments
1
Dominion - Dominion
Virginia Power
Larry Nash
Negative
Comments
Submitted
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Negative
Comments
Submitted
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
None
N/A
Louis Guidry
Douglas Webb
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
None
N/A
Abstain
N/A
Nicolas Turcotte
Abstain
N/A
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Third-Party
Comments
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
Third-Party
Comments
1
NB Power
Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public
Power District
Jamison Cawley
Negative
Third-Party
Comments
1
New York Power
Authority
Salvatore Spagnolo
Negative
Comments
Submitted
1
NextEra Energy -
Mike ONeil
Negative
Comments
Oshani
Pathirane
Scott Miller
Florida Power and
Light Co.
Submitted
1
NiSource - Northern
Indiana Public
Service Co.
Charles Raney
Negative
Third-Party
Comments
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Affirmative
N/A
1
Oncor Electric
Delivery
Rod Kinard
Negative
Comments
Submitted
1
OTP - Otter Tail
Power Company
Charles Wicklund
Negative
Third-Party
Comments
1
Peak Reliability
Jared Shakespeare
None
N/A
1
PHI - Potomac
Electric Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
None
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
Tammy Porter
1
Sacramento
Municipal Utility
District
Tim Kelley
1
Salt River Project
1
Joe Tarantino
Affirmative
N/A
Steven Cobb
Affirmative
N/A
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
Third-Party
Comments
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Negative
Comments
Submitted
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
None
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
Comments
Submitted
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent
Electricity System
Operator
Leonard Kula
Affirmative
N/A
2
ISO New England,
Inc.
Michael Puscas
Negative
Comments
Submitted
2
Midcontinent ISO,
Inc.
Terry BIlke
Negative
Third-Party
Comments
2
New York
Independent System
Operator
Gregory Campoli
Negative
Third-Party
Comments
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power
Pool, Inc. (RTO)
Charles Yeung
None
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
None
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
Kathleen
Goodman
William Temple
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Third-Party
Comments
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Affirmative
N/A
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Negative
Comments
Submitted
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Negative
Comments
Submitted
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Affirmative
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
Darnez
Gresham
Bill Hughes
Louis Guidry
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Negative
Third-Party
Comments
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Negative
Comments
Submitted
3
Great River Energy
Brian Glover
Negative
Third-Party
Comments
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric
System
Jason Fortik
Negative
Third-Party
Comments
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
Third-Party
Comments
3
National Grid USA
Brian Shanahan
Negative
Third-Party
Comments
3
Nebraska Public
Power District
Tony Eddleman
Negative
Third-Party
Comments
3
New York Power
Authority
David Rivera
Negative
Comments
Submitted
Douglas Webb
Oshani
Pathirane
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
Negative
Third-Party
Comments
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Affirmative
N/A
3
PHI - Potomac
Electric Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Affirmative
N/A
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento
Municipal Utility
District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power
Electric Cooperative
Jeff Neas
Affirmative
N/A
Joe Tarantino
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Affirmative
N/A
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
None
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Negative
Third-Party
Comments
4
Austin Energy
Tina Garvey
None
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
Affirmative
N/A
Bill Hughes
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Negative
Third-Party
Comments
4
Illinois Municipal
Electric Agency
Bob Thomas
Affirmative
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Negative
Third-Party
Comments
4
Modesto Irrigation
District
Spencer Tacke
None
N/A
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
Joe Tarantino
4
Utility Services, Inc.
Brian Evans-Mongeon
None
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Third-Party
Comments
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of
San Francisco
Daniel Mason
Affirmative
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy -
David Greyerbiehl
Affirmative
N/A
Consumers Energy
Company
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Negative
Comments
Submitted
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Affirmative
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power
and Light Co.
Harold Wyble
Negative
Comments
Submitted
5
Great River Energy
Preston Walsh
Negative
Third-Party
Comments
5
Hydro-Qu?bec
Production
Roger Dufresne
Abstain
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Negative
Third-Party
Comments
5
Los Angeles
Kenneth Silver
Affirmative
N/A
Kelly Dash
Douglas Webb
Department of Water
and Power
5
Lower Colorado River
Authority
Dixie Wells
Negative
Comments
Submitted
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Third-Party
Comments
5
NB Power
Corporation
Rob Vance
Abstain
N/A
5
Nebraska Public
Power District
Don Schmit
Negative
Third-Party
Comments
5
New York Power
Authority
Wayne Sipperly
Negative
Comments
Submitted
5
NextEra Energy
Allen Schriver
Affirmative
N/A
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Affirmative
N/A
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail
Power Company
Cathy Fogale
Negative
Third-Party
Comments
5
Pacific Gas and
Electric Company
Alex Chua
None
N/A
5
Platte River Power
Tyson Archie
Affirmative
N/A
Scott Miller
Authority
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation,
LLC
Donald Lock
Affirmative
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa
Electric Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
Brandy Spraker
Affirmative
N/A
Joe Tarantino
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Affirmative
N/A
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Negative
Comments
Submitted
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Negative
Comments
Submitted
6
Great River Energy
Donna Stephenson
6
Lower Colorado River
Authority
6
Michael
Brytowski
Negative
Third-Party
Comments
Michael Shaw
None
N/A
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
Third-Party
Comments
6
New York Power
Authority
Shivaz Chopra
Negative
Comments
Submitted
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Third-Party
Comments
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
Third-Party
Comments
6
Platte River Power
Authority
Carol Ballantine
Affirmative
N/A
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Affirmative
N/A
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
Nick Braden
Joe Tarantino
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa
Electric Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Affirmative
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Attorney General
Frederick Plett
Affirmative
N/A
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Abstain
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
Third-Party
Comments
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
Amy Casuscelli
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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BALLOT RESULTS
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1 Non-binding Poll IN 1 NB
Voting Start Date: 12/31/2015 12:01:00 AM
Voting End Date: 1/11/2016 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 222
Total Ballot Pool: 269
Quorum: 82.53
Weighted Segment Value: 74.38
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
1
68
1
31
0.721
12
0.279
0
15
10
Segment:
2
8
0.5
3
0.3
2
0.2
0
2
1
Segment:
3
63
1
28
0.757
9
0.243
0
14
12
Segment:
4
20
1
13
1
0
0
0
4
3
Segment:
5
60
1
21
0.7
9
0.3
0
17
13
Segment:
6
37
1
17
0.708
7
0.292
0
7
6
Segment:
7
2
0
0
0
0
0
0
0
2
Segment:
8
1
0
0
0
0
0
0
1
0
0
0
0
0
0
Segment
Segment:
2 3.0.0.00.2
2
0.2
© 2016
- NERC Ver
Machine Name:
ERODVSBSWB01
9
Negative
Votes
w/o
Comment
Abstain
No
Vote
Segment:
10
8
0.6
4
0.4
2
0.2
0
2
0
Totals:
269
6.3
119
4.786
41
1.514
0
62
47
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Abstain
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Abstain
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Comments
Submitted
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Tony Kroskey
None
N/A
Cooperative, Inc.
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Abstain
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Negative
Comments
Submitted
1
Dairyland Power
Cooperative
Robert Roddy
Abstain
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Abstain
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Affirmative
N/A
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Negative
Comments
Submitted
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
Abstain
N/A
1
Hydro-Qu?bec
TransEnergie
Nicolas Turcotte
Negative
Comments
Submitted
Louis Guidry
Douglas Webb
Oshani
Pathirane
1
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
Nebraska Public
Power District
Jamison Cawley
Abstain
N/A
1
New York Power
Authority
Salvatore Spagnolo
Negative
Comments
Submitted
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern
Indiana Public
Service Co.
Charles Raney
Negative
Comments
Submitted
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Negative
Comments
Submitted
1
Oncor Electric
Delivery
Rod Kinard
Abstain
N/A
Scott Miller
Tammy Porter
1
Peak Reliability
Jared Shakespeare
None
N/A
1
Platte River Power
Authority
John Collins
Abstain
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
None
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Abstain
N/A
1
Sacramento
Municipal Utility
District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
John Shaver
Negative
Comments
Joe Tarantino
Transmission
Cooperative, Inc.
Submitted
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
None
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
Comments
Submitted
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent
Electricity System
Operator
Leonard Kula
Negative
Comments
Submitted
2
Midcontinent ISO,
Inc.
Terry BIlke
Abstain
N/A
2
New York
Independent System
Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
William Temple
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Abstain
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Abstain
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Abstain
N/A
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Comments
Submitted
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Affirmative
N/A
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Abstain
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Negative
Comments
Submitted
Darnez
Gresham
Louis Guidry
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Abstain
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Abstain
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Negative
Comments
Submitted
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric
System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
Comments
Submitted
Douglas Webb
Oshani
Pathirane
Scott Miller
3
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public
Power District
Tony Eddleman
Abstain
N/A
3
New York Power
Authority
David Rivera
Negative
Comments
Submitted
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
Negative
Comments
Submitted
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Negative
Comments
Submitted
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
None
N/A
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Abstain
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento
Municipal Utility
District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company -
R. Scott Moore
Affirmative
N/A
Joe Tarantino
Alabama Power
Company
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Abstain
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
None
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Abstain
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Abstain
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Abstain
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Abstain
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
None
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Austin Energy
Jeanie Doty
Abstain
N/A
5
Avista - Avista
Corporation
Steve Wenke
Abstain
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Abstain
N/A
5
BC Hydro and Power
Authority
Clement Ma
Abstain
N/A
Joe Tarantino
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Comments
Submitted
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Abstain
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
None
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Abstain
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Abstain
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power
Harold Wyble
Affirmative
N/A
Louis Guidry
Kelly Dash
Douglas Webb
and Light Co.
5
Great River Energy
Preston Walsh
Negative
Comments
Submitted
5
Hydro-Qu?bec
Production
Roger Dufresne
Negative
Comments
Submitted
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Abstain
N/A
5
Lower Colorado River
Authority
Dixie Wells
Abstain
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Comments
Submitted
5
Nebraska Public
Power District
Don Schmit
Abstain
N/A
5
New York Power
Authority
Wayne Sipperly
Negative
Comments
Submitted
5
NextEra Energy
Allen Schriver
Negative
Comments
Submitted
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Negative
Comments
Submitted
Scott Miller
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Abstain
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
None
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
Tennessee Valley
M Lee Thomas
None
N/A
Joe Tarantino
Authority
5
Westar Energy
stephanie johnson
Abstain
N/A
5
Xcel Energy, Inc.
David Lemmons
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Abstain
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Negative
Comments
Submitted
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Abstain
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Negative
Comments
Submitted
6
Lower Colorado River
Authority
Michael Shaw
None
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
Louis Guidry
6
Muscatine Power and
Water
Ryan Streck
Negative
Comments
Submitted
6
New York Power
Authority
Shivaz Chopra
Affirmative
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Abstain
N/A
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Negative
Comments
Submitted
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
Comments
Submitted
6
Platte River Power
Authority
Carol Ballantine
Abstain
N/A
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
None
N/A
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
Joe Tarantino
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
None
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Affirmative
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Abstain
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Negative
Comments
Submitted
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Abstain
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Negative
Comments
Submitted
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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1
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BALLOT RESULTS
Survey: View Survey Results (/SurveyResults/Index/38)
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 Non-binding Poll IN 1 NB
Voting Start Date: 12/31/2015 12:01:00 AM
Voting End Date: 1/11/2016 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 222
Total Ballot Pool: 269
Quorum: 82.53
Weighted Segment Value: 75.44
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
68
1
31
0.721
12
0.279
0
14
11
Segment:
2
8
0.5
4
0.4
1
0.1
0
2
1
Segment:
3
63
1
31
0.738
11
0.262
0
9
12
Segment:
4
20
1
13
0.929
1
0.071
0
3
3
Segment:
5
60
1
27
0.75
9
0.25
0
12
12
Segment:
6
37
1
17
0.68
8
0.32
0
6
6
Segment:
7
2
0
0
0
0
0
0
0
2
0
0
0
1
0
0
0
0
1
0
Segment
Segment: 1
0
0
0
8
© 2016 - NERC Ver 3.0.0.0 Machine Name: ERODVSBSWB02
Segment: 2
0.1
1
0.1
9
Segment:
10
8
0.5
5
0.5
0
0
0
3
0
Totals:
269
6.1
129
4.818
42
1.282
0
51
47
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
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Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
Comments
Submitted
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Abstain
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Abstain
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Terry Harbour
Negative
Comments
Submitted
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Tony Kroskey
None
N/A
Cooperative, Inc.
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric
Power Cooperative
(Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Abstain
N/A
1
Con Ed Consolidated Edison
Co. of New York
Chris de Graffenried
Negative
Comments
Submitted
1
Dairyland Power
Cooperative
Robert Roddy
Abstain
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia
Transmission
Corporation
Jason Snodgrass
Negative
Comments
Submitted
1
Great Plains Energy Kansas City Power
and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
None
N/A
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
Abstain
N/A
1
Hydro-Qu?bec
TransEnergie
Nicolas Turcotte
Affirmative
N/A
1
IDACORP - Idaho
Laura Nelson
Affirmative
N/A
Louis Guidry
Douglas Webb
Oshani
Pathirane
Power Company
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Abstain
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric
Power Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
Comments
Submitted
1
National Grid USA
Michael Jones
Negative
Comments
Submitted
1
Nebraska Public
Power District
Jamison Cawley
Abstain
N/A
1
New York Power
Authority
Salvatore Spagnolo
Negative
Comments
Submitted
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Negative
Comments
Submitted
1
NiSource - Northern
Indiana Public
Service Co.
Charles Raney
Negative
Comments
Submitted
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Affirmative
N/A
1
Oncor Electric
Delivery
Rod Kinard
Negative
Comments
Submitted
1
Peak Reliability
Jared Shakespeare
None
N/A
Scott Miller
Tammy Porter
1
Platte River Power
Authority
John Collins
Abstain
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
None
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
None
N/A
1
PSEG - Public
Service Electric and
Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant
County, Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Abstain
N/A
1
Sacramento
Municipal Utility
District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Abstain
N/A
1
Sho-Me Power
Electric Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
John Shaver
Negative
Comments
Submitted
Joe Tarantino
Cooperative, Inc.
1
Tacoma Public
Utilities (Tacoma,
WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Abstain
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating
Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
None
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
Comments
Submitted
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent
Electricity System
Operator
Leonard Kula
Affirmative
N/A
2
Midcontinent ISO,
Inc.
Terry BIlke
Abstain
N/A
2
New York
Independent System
Operator
Gregory Campoli
Abstain
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
William Temple
3
Anaheim Public
Utilities Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
Comments
Submitted
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Affirmative
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Negative
Comments
Submitted
3
BC Hydro and Power
Authority
Faramarz Amjadi
Abstain
N/A
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy MidAmerican Energy
Co.
Thomas Mielnik
Negative
Comments
Submitted
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric
Power Cooperative
(Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Springs
Mark Schultz
Affirmative
N/A
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed Consolidated Edison
Co. of New York
Peter Yost
Negative
Comments
Submitted
Darnez
Gresham
Louis Guidry
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Negative
Comments
Submitted
3
Great Plains Energy Kansas City Power
and Light Co.
Jessica Tucker
Negative
Comments
Submitted
3
Great River Energy
Brian Glover
Negative
Comments
Submitted
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric
System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric
Power Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
Comments
Submitted
Douglas Webb
Oshani
Pathirane
Scott Miller
3
National Grid USA
Brian Shanahan
Negative
Comments
Submitted
3
Nebraska Public
Power District
Tony Eddleman
Abstain
N/A
3
New York Power
Authority
David Rivera
Negative
Comments
Submitted
3
NiSource - Northern
Indiana Public
Service Co.
Ramon Barany
Negative
Comments
Submitted
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
None
N/A
3
PSEG - Public
Service Electric and
Gas Co.
Jeffrey Mueller
Abstain
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento
Municipal Utility
District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Abstain
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company -
R. Scott Moore
Affirmative
N/A
Joe Tarantino
Alabama Power
Company
3
Tacoma Public
Utilities (Tacoma,
WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Abstain
N/A
3
TECO - Tampa
Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
None
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
3
Turlock Irrigation
District
James Ramos
None
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Affirmative
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Abstain
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Negative
Comments
Submitted
4
Illinois Municipal
Electric Agency
Bob Thomas
Abstain
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant
County, Washington
Yvonne McMackin
None
N/A
4
Sacramento
Municipal Utility
District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Abstain
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public
Utilities (Tacoma,
WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
None
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
Comments
Submitted
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Negative
Comments
Submitted
5
BC Hydro and Power
Authority
Clement Ma
Abstain
N/A
Joe Tarantino
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Comments
Submitted
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Abstain
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
Affirmative
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Con Ed Consolidated Edison
Co. of New York
Brian O'Boyle
Negative
Comments
Submitted
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Abstain
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy -
Harold Wyble
Negative
Comments
Louis Guidry
Kelly Dash
Douglas Webb
Kansas City Power
and Light Co.
Submitted
5
Great River Energy
Preston Walsh
Negative
Comments
Submitted
5
Hydro-Qu?bec
Production
Roger Dufresne
Abstain
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric
System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Abstain
N/A
5
Lower Colorado River
Authority
Dixie Wells
Negative
Comments
Submitted
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
Comments
Submitted
5
Nebraska Public
Power District
Don Schmit
Abstain
N/A
5
New York Power
Authority
Wayne Sipperly
Negative
Comments
Submitted
5
NextEra Energy
Allen Schriver
Abstain
N/A
5
NiSource - Northern
Indiana Public
Service Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Affirmative
N/A
5
Oglethorpe Power
Teresa Czyz
None
N/A
Scott Miller
Corporation
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
None
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Abstain
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant
County, Washington
Alex Ybarra
None
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento
Municipal Utility
District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public
Utilities (Tacoma,
WA)
Chris Mattson
Affirmative
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
Tennessee Valley
Authority
M Lee Thomas
None
N/A
Joe Tarantino
5
Westar Energy
stephanie johnson
Affirmative
N/A
5
Xcel Energy, Inc.
David Lemmons
Abstain
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
Comments
Submitted
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
None
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Abstain
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed Consolidated Edison
Co. of New York
Robert Winston
Negative
Comments
Submitted
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power
and Light Co.
Chris Bridges
Douglas Webb
Negative
Comments
Submitted
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Negative
Comments
Submitted
6
Lower Colorado River
Authority
Michael Shaw
None
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Muscatine Power and
Ryan Streck
Negative
Comments
Louis Guidry
Water
Submitted
6
New York Power
Authority
Shivaz Chopra
Negative
Comments
Submitted
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Abstain
N/A
6
NiSource - Northern
Indiana Public
Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
Comments
Submitted
6
Platte River Power
Authority
Carol Ballantine
Abstain
N/A
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
None
N/A
6
Sacramento
Municipal Utility
District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Abstain
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public
Utilities (Tacoma,
WA)
Rick Applegate
Affirmative
N/A
Joe Tarantino
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
None
N/A
6
Westar Energy
Megan Wagner
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Abstain
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Abstain
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power
Pool Regional Entity
Bob Reynolds
Abstain
N/A
10
Texas Reliability
Entity, Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Previous
1
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BAL-005-1 – Balancing Authority Control
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
This is the final posting of the draft standard for a 10-day final ballot.
Completed Actions
Date
Standards Committee approved SAR for posting
June 10, 2014
SAR Posted for comment
July 16, 2014
Standard posted for 45-day comment period and initial ballot
July 30, 2015
Standard posted for 45-day comment period and successive ballot
November 10, 2015
Anticipated Actions
Date
Final ballot
January – February
2016
NERC Board adoption
February 2016
Draft #3 of Standard BAL-005-1: January, 2016
Page 1 of 19
BAL-005-1 – Balancing Authority Control
New or Modified Terms Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard.
Term:
Rationale for Modification of AGC: The original definition of AGC reflects "how to" control
and automatically adjust equipment in a Balancing Authority Area and does not reflect the
current technology nor the evolution of the industry from a “Control Area” to a “Balancing
Area”. In addition, it was telling the entity "how to do it" rather than allowing the entity to
perform the necessary functions in the most effective and reliable manner.
The new definition reflects a process and allows the entity the flexibility to perform the
necessary function in the most effective and reliable manner to address such process
without being instructed on "how to do it".
Automatic Generation Control (AGC): A process designed and used to automatically adjust a
Balancing Authority Areas’ Demand and/or resources to help maintain the Reporting ACE in that
of a Balancing Authority Area within the bounds required by applicable NERC Reliability
Standards.
Actual Frequency (F A ): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NI A ): The algebraic sum of actual megawatt transfers across all Tie
Lines, including Pseudo-Ties, to and from all Adjacent Balancing Authority areas within the
same Interconnection. Actual megawatt transfers on asynchronous DC tie lines that are directly
connected to another Interconnection are excluded from Actual Net Interchange.
Scheduled Net Interchange (NI S ): The algebraic sum of all scheduled megawatt transfers,
including Dynamic Schedules, to and from all Adjacent Balancing Authority areas within the
same Interconnection, including the effect of scheduled ramps. Scheduled megawatt transfers
on asynchronous DC tie lines directly connected to another Interconnection are excluded from
Scheduled Net Interchange.
Interchange Meter Error (I ME ): A term, normally zero, used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the Reporting ACE
calculation.
Draft #3 of Standard BAL-005-1: January, 2016
Page 2 of 19
BAL-005-1 – Balancing Authority Control
Automatic Time Error Correction (I ATEC ): The addition of a component to the ACE equation for
the Western Interconnection that modifies the control point for the purpose of continuously
paying back Primary Inadvertent Interchange to correct accumulated time error. Automatic
Time Error Correction is only applicable in the Western Interconnection.
Iࢀࡱ =
Τࢌࢌ ࢋࢇ
PIIࢇࢉࢉ࢛
(ିࢅ)ࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of I ATEC shall not exceed L max .
I ATEC shall be zero when operating in any other AGC mode.
x
L max is the maximum value allowed for I ATEC set by each BA between 0.2*|B i | and L 10 ,
0.2*|B i |чL max чL 10 .
x
x
L 10 = 1.65 כɂଵ ඥ(െ10B୧ )(െ10Bୗ ) .
H 10 is a constant derived from the targeted frequency bound. It is the targeted root-mean-square
(RMS) value of ten-minute average frequency error based on frequency performance over a given
year. The bound, H 10 , is the same for every Balancing Authority Area within an Interconnection.
x
x
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The value
of H is set to 3.
x
B i = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
x
x
x
B S = Sum of the minimum Frequency Bias Settings for the Interconnection (MW / 0.1 Hz).
Primary Inadvertent Interchange (PII hourly ) is (1-Y) * (II actual - B i Ύȴd ͬϲͿ
II actual is the hourly Inadvertent Interchange for the last hour.
ȴd ŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞ ƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶtime
monitor,where: ȴd сd end hour – TE begin hour – TD adj – (t)*(TE offset )
TD adj is the Reliability Coordinator adjustment for differences with Interconnection time
monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the hour.
TE offset is 0.000 or +0.020 or -0.020.
PII accum is the Balancing Authority Area’s accumulated PII hourly in MWh. An On-Peak and OffPeak accumulation accounting is required,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
= ࢇ࢙࢚ ࢋ࢘ࢊᇱ ࢙ PIIࢇࢉࢉ࢛
+ PIIࢎ࢛࢘࢟
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area Control Error
(ACE) measured in MW includes the difference between the Balancing Authority Area’s Actual
Net Interchange and its Scheduled Net Interchange, plus its Frequency Bias Setting obligation,
plus correction for any known meter error. In the Western Interconnection, Reporting ACE
includes Automatic Time Error Correction (ATEC).
Draft #3 of Standard BAL-005-1: January, 2016
Page 3 of 19
BAL-005-1 – Balancing Authority Control
Reporting ACE is calculated as follows:
Reporting ACE = (NI A оE/ S ͿоϭϬ;& A о& S ) – I ME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NI A оE/ S Ϳо10B (F A о& S ) – I ME + I ATEC
Where:
x NI A
=
Actual Net Interchange.
x NI S
=
Scheduled Net Interchange.
x B
=
Frequency Bias Setting.
x FA
=
Actual Frequency.
x FS
=
Scheduled Frequency.
x I ME
=
Interchange Meter Error.
x I ATEC
=
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie Line Bias (TLB) Control and require
the use of an ACE equation similar to the Reporting ACE defined above. Any modification(s) to
this specified Reporting ACE equation that is(are) implemented for all BAAs on an
Interconnection and is(are) consistent with the following four principles of Tie Line Bias control
will provide a valid alternative to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the sum of all
BAAs’ generation, load, and loss is the same as total Interconnection generation, load,
and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all times
and the sum of all BAAs’ Actual Net Interchange values is equal to zero at all times;
3. The use of a common Scheduled Frequency F S for all BAAs at all times; and,
4. Excludes metering or computational errors. (The inclusion and use of the I ME term
corrects for known metering or computational errors.)
Pseudo-Tie: A time-varying energy transfer that is updated in Real-time and included in the
Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected Balancing
Authorities’ Reporting ACE equation (or alternate control processes).
Rationale for Modification of Balancing Authority: The SDT has recommended to change
the definition of Automatic Generation Control (AGC) and to be consistent, with the change
to AGC, the SDT recommends changing the definition of a Balancing Authority. In addition,
Project 2015-04 Alignment of Terms SDT brought to our attention of the inconsistent use of
"load-interchange-generation" and through the Alignment of Terms project it was
recommend a SDT associated with a BAL Standard address the issue. The proposed changes
reflects a Balancing Authority.
Draft #3 of Standard BAL-005-1: January, 2016
Page 4 of 19
BAL-005-1 – Balancing Authority Control
Balancing Authority: The responsible entity that integrates resource plans ahead of time,
maintains Demand and resource balance within a Balancing Authority Area, and supports
Interconnection frequency in real time.
Draft #3 of Standard BAL-005-1: January, 2016
Page 5 of 19
BAL-005-1 – Balancing Authority Control
When this standard has received ballot approval, the text boxes will be moved to the
Supplemental Material Section of the standard.
A. Introduction
1.
Title:
Balancing Authority Control
2.
Number:
BAL-005-1
3.
Purpose: This standard establishes requirements for acquiring data necessary to
calculate Reporting Area Control Error (Reporting ACE). The standard also specifies a
minimum periodicity, accuracy, and availability requirement for acquisition of the
data and for providing the information to the System Operator.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Balancing Authority
Effective Date: See Implementation Plan for BAL-005-1
B. Requirements and Measures
Rationale for Requirement R1: Real-time operation of a Balancing Authority requires
real-time information. A sufficient scan rate is key to an Operator’s trust in real-time
information. Without a sufficient scan rate, an operator may question the accuracy of
data during events, which would degrade the operator’s ability to maintain reliability.
R1.
The Balancing Authority shall use a design scan rate of no more than six seconds in
acquiring data necessary to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
M1. Each Balancing Authority will have dated documentation demonstrating that the data
necessary to calculate Reporting ACE was designed to be scanned at a rate of no more
than six seconds. Acceptable evidence may include historical data, dated archive files;
or data from other databases, spreadsheets, or displays that demonstrate
compliance.
Rationale for Requirement R2: The RC is responsible for coordinating the reliability of
bulk electric systems for member BA’s. When a BA is unable to calculate its ACE for an
extended period of time, this information must be communicated to the RC within 15
Draft #3 of Standard BAL-005-1: January, 2016
Page 6 of 19
BAL-005-1 – Balancing Authority Control
minutes thereafter so that the RC has sufficient knowledge of system conditions to assess
any unintended reliability consequences that may occur on the wide area.
R2.
A Balancing Authority that is unable to calculate Reporting ACE for more than 30consecutive minutes shall notify its Reliability Coordinator within 45 minutes of the
beginning of the inability to calculate Reporting ACE. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
M2. Each Balancing Authority will have dated records to show when it was unable to
calculate Reporting ACE for more than 30 consecutive minutes and that it notified its
Reliability Coordinator within 45 minutes of the beginning of the inability to calculate
Reporting ACE. Such evidence may include, but is not limited to, dated voice
recordings, operating logs, or other communication documentation.
Rationale for Requirement R3: Frequency is the basic measurement for interconnection
health, and a critical component for calculating Reporting ACE. Without sufficient
available frequency data the BA operator will lack situational awareness and will be
unable to make correct decisions when maintaining reliability.
R3.
Each Balancing Authority shall use frequency metering equipment for the calculation
of Reporting ACE: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
3.1. that is available a minimum of 99.95% for each calendar year; and,
3.2. with a minimum accuracy of 0.001 Hz.
M3. The Balancing Authority shall have evidence such as dated documents or other
evidence in hard copy or electronic format showing the frequency metering
equipment used for the calculation of Reporting ACE had a minimum availability of
99.95% for each calendar year and had a minimum accuracy of 0.001 Hz to
demonstrate compliance with Requirement R3.
Rationale for Requirement R4: System operators utilize Reporting ACE as a primary
metric to determine operating actions or instructions. When data inputs into the ACE
calculation are incorrect, the operator should be made aware through visual display.
When an operator questions the validity of data, actions are delayed and the probability
of adverse events occurring can increase.
Draft #3 of Standard BAL-005-1: January, 2016
Page 7 of 19
BAL-005-1 – Balancing Authority Control
R4.
The Balancing Authority shall make available to the operator information associated
with Reporting ACE including, but not limited to, quality flags indicating missing or
invalid data. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
M4. Each Balancing Authority Area shall have evidence such as a graphical display or dated
alarm log that provides indication of data validity for the real-time Reporting ACE
based on both the calculated result and all of the associated inputs therein.
Rationale for Requirement R5: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Since Reporting ACE is a measure of
the BA’s reliability performance for BAL-001, and BAL-002, it is critical that Reporting ACE
be sufficiently available to assure reliability.
R5.
Each Balancing Authority’s system used to calculate Reporting ACE shall be available a
minimum of 99.5% of each calendar year. [Violation Risk Factor: Medium] [Time
Horizon: Operations Assessment]
M5. Each Balancing Authority will have dated documentation demonstrating that the
system necessary to calculate Reporting ACE has a minimum availability of 99.5% for
each calendar year. Acceptable evidence may include historical data, dated archive
files; or data from other databases, spreadsheets, or displays that demonstrate
compliance.
Rationale for Requirement R6: Reporting ACE is a measure of the BA’s reliability
performance for BAL-001, and BAL-002. Without a process to address persistent errors in
the ACE calculation, the operator can lose trust in the validity of Reporting ACE resulting
in delayed or incorrect decisions regarding the reliability of the bulk electric system.
A successful Operating Process must include the ability for hourly accumulated Tie Line
MWH values to be agreed-upon between Balancing Authority Areas to aid in the
identification errors and assign such errors to the appropriate Balancing Authority Areas
for mitigation if necessary.
Instantaneous tie line flows between BAs cannot be effectively compared in real time.
Methods to confirm accuracy of instantaneous metering is achieved through other
means. The integration of instantaneous metered values is compared with accumulated
MWh values to determine the accuracy of (error included in) the instantaneous metering
for each BA. This comparison indicates the accuracy (amount of error) for each BA’s own
instantaneous metering as compared to its own accumulated MWh metering. However,
it does not confirm that the accumulated MWh metering for one BA is equivalent to the
accumulated MWh metering for the adjacent BA on the same tie line. This can only be
Draft #3 of Standard BAL-005-1: January, 2016
Page 8 of 19
BAL-005-1 – Balancing Authority Control
confirmed by comparing the accumulated MWh value for one BA to the accumulated
MWh value for the adjacent BA. If these two values are the same, any problem with the
metering is identified by the difference between the integrated instantaneous MWhs and
the accumulated MWh for that BA. However, if there is a difference between the
accumulated MWhs between the two adjacent BAs, those BAs must agree upon a
common value to use for that hour for that tie line in order to assign responsibility for
managing the error represented by the difference between their accumulated values. If
the BAs do not agree upon a value, the difference between the accumulated values will
not be included in their error mitigation process and that error will therefore be passed to
the interconnection as a frequency control burden.
R6.
Each Balancing Authority that is within a multiple Balancing Authority Interconnection
shall implement an Operating Process to identify and mitigate errors affecting the
accuracy of scan rate data used in the calculation of Reporting ACE for each Balancing
Authority Area. [Violation Risk Factor: Medium] [Time Horizon: Same-day Operations
]
M6. Each Balancing Authority shall have a current Operating Process meeting the
provisions of Requirement R6 and evidence to show that the process was
implemented, such as dated communications or incorporation in System Operator
task verification.
Rationale for Requirement R7: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Common source data is critical to
calculating Reporting ACE that is consistent between Balancing Authorities. When data
sources are not common, confusion can be created between BAs resulting in delayed or
incorrect operator action.
The intent of Requirement R7 Part 7.1 is to provide accuracy in the measurement and
calculations used in Reporting ACE. It specifies the need for common metering points for
instantaneous values for the Tie Line megawatt flow values between Balancing Authority
Areas. Common data source requirements also apply to instantaneous values for pseudoties and dynamic schedules, and can extend to more than two Balancing Authorities that
participate in allocating shares of a generation resource in supplementary regulation, for
example.
The intent of Requirement R7 Part 7.2 is to enable accuracy in the measurements and
calculations used in Reporting ACE. It specifies the need for common metering points for
hourly accumulated values for the time synchronized tie line MWh values agreed-upon
between Balancing Authority Areas. These time synchronized agreed-upon values are
necessary for use in the Operating Process required in R6 to identify and mitigate errors
Draft #3 of Standard BAL-005-1: January, 2016
Page 9 of 19
BAL-005-1 – Balancing Authority Control
in the scan rate values used in Reporting ACE.
R7.
Each Balancing Authority shall ensure that each Tie Line, Pseudo-Tie, and Dynamic
Schedule with an Adjacent Balancing Authority is equipped with: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
7.1. a common source to provide information to both Balancing Authorities for the
scan rate values used in the calculation of Reporting ACE; and,
7.2. a time synchronized common source to determine hourly megawatt-hour values
agreed-upon to aid in the identification and mitigation of errors under the
Operating Process as developed in Requirement R6.
M7. The Balancing Authority shall have dated evidence such as voice recordings or
transcripts, operator logs, electronic communications, or other equivalent evidence
that will be used to demonstrate a common source for the components used in the
calculation of Reporting ACE with its Adjacent Balancing Authority.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention period(s) identify the period of time an
entity is required to retain specific evidence to demonstrate compliance. For
instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask
an entity to provide other evidence to show that it was compliant for the fulltime period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
x
The applicable entity shall keep data or evidence to show compliance for
the current year, plus three previous calendar years.
1.3. Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will
be used to evaluate data or information for the purpose of assessing
performance or outcomes with the associated Reliability Standard.
Draft #3 of Standard BAL-005-1: January, 2016
Page 10 of 19
BAL-005-1 – Balancing Authority Control
1.4. Additional Compliance Information
None
Draft #3 of Standard BAL-005-1: January, 2016
Page 11 of 19
Real-time
Operations
Real-time
Operations
R1.
R2.
Medium
Medium
VRF
Draft #3 of Standard BAL-005-1: January, 2016
Time
Horizon
R#
Table of Compliance Elements
N/A
Lower VSL
The Balancing
Authority failed to
notify its Reliability
Coordinator within
45 minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator within
no more than 50
minutes from the
beginning of the
BAL-005-1 – Balancing Authority Control
The Balancing
Authority failed to
notify its Reliability
Coordinator within 50
minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator with mo
more than 55
minutes from the
beginning of an
N/A
Moderate VSL
The Balancing
Authority failed to
notify its Reliability
Coordinator within
55 minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator with no
more than 60
minutes from the
beginning of an
N/A
High VSL
Violation Severity Levels
Page 12 of 19
The Balancing
Authority failed to
notify its Reliability
Coordinator within 60
minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE.
Balancing Authority
was using a design
scan rate of greater
than six seconds to
acquire the data
necessary to calculate
Reporting ACE.
Severe VSL
Real-time
Operations
R4.
Medium
Medium
Draft #3 of Standard BAL-005-1: January, 2016
Real-time
Operations
R3.
N/A
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.95% of the
calendar year but
was available greater
than or equal to
99.94 % of the
calendar year.
inability to calculate
Reporting ACE.
BAL-005-1 – Balancing Authority Control
N/A
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.94% of the
calendar year but was
available greater than
or equal to 99.93 % of
the calendar year.
inability to calculate
Reporting ACE.
N/A
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.93% of the
calendar year but
was available greater
than or equal to
99.92 % of the
calendar year.
inability to calculate
Reporting ACE.
Page 13 of 19
The Balancing
Authority failed to
make available
information
indicating missing or
invalid data
associated with
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE failed
to have a minimum
accuracy of 0.001 Hz.
Or
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.92% of the
calendar year
Same-day
Operations
Operations
Planning
R6.
R7.
Medium
Medium
Medium
Draft #3 of Standard BAL-005-1: January, 2016
Operations
Assessment
R5.
N/A
N/A
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.5% of the calendar
year but was
available greater
than or equal to 99.4
% of the calendar
year.
BAL-005-1 – Balancing Authority Control
N/A
N/A
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.4% of the calendar
year but was
available greater than
or equal to 99.3 % of
the calendar year.
N/A
N/A
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.3% of the calendar
year but was
available greater
than or equal to 99.2
% of the calendar
year.
Page 14 of 19
The Balancing
Authority failed to
use a common source
for Tie Lines, Pseudoties and Dynamic
The Balancing
Authority failed to
implement an
Operating Process to
identify and mitigate
errors affecting the
scan rate accuracy of
data used in the
calculation of
Reporting ACE.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.2% of the calendar
year.
Reporting ACE to its
operators.
Date
Draft #3 of Standard BAL-005-1: January, 2016
Version
Version History
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
BAL-005-1 – Balancing Authority Control
Action
Change Tracking
Page 15 of 19
The Balancing
Authority failed to
use a time
synchronized
common source for
hourly megawatt
hour values that are
agreed-upon to aid in
the identification and
mitigation of errors.
Or
Schedules with its
Adjacent Balancing
Authorities
April 1, 2005
August 8, 2005
December 19,
2007
January 16,
2008
February 12,
2008
October 29,
2008
May 13, 2009
March 8, 2012
September 13,
2012
February 7,
2013
0
0
0a
0a
0b
0.1b
0.1b
0.2b
0.2b
0.2b
Draft #3 of Standard BAL-005-1: January, 2016
February 8,
2005
0
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
FERC approved – Updated Effective Date
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
FERC approved – Updated Effective Date
BOT approved errata changes; updated version
number to “0.1b”
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Removed “Proposed” from Effective Date
Effective Date
Adopted by NERC Board of Trustees
BAL-005-1 – Balancing Authority Control
Addition
Errata
Addition
Errata
Replacement
Errata
Addition
Errata
New
New
Page 16 of 19
November 21,
2013
R2 and associated elements approved by FERC for
retirement as part of the Paragraph 81 project
(Project 2013-02) effective January 21, 2014.
Draft #3 of Standard BAL-005-1: January, 2016
Page 17 of 19
Standards Attachments
NOTE: Use this section for attachments or other documents that are referenced in the standard as part of the requirements. These
should appear after the end of the standard template and before the Supplemental Material. If there are none, delete this section.
0.2b
BAL-005-1 – Balancing Authority Control
Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft #3 of Standard BAL-005-1: January, 2016
Page 18 of 19
Supplemental Material
Rationale
Upon Board approval, the text from the rationale boxes will be moved to this section.
Draft #3 of Standard BAL-005-1: January, 2016
Page 19 of 19
BALͲ005Ͳ1–BalancingAuthorityControl
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthefinalpostingofthedraftstandardfora10Ͳdayfinalballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARPostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentperiodandinitialballot
July30,2015
Standardpostedfor45Ͳdaycommentperiodandsuccessiveballot
November10,2015
Anticipated Actions
Date
Finalballot
January–February
2016
NERCBoardadoption
February2016
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page1of18
BALͲ005Ͳ1–BalancingAuthorityControl
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:
RationaleforModificationofAGC:TheoriginaldefinitionofAGCreflects"howto"control
andautomaticallyadjustequipmentinaBalancingAuthorityAreaanddoesnotreflectthe
currenttechnologynortheevolutionoftheindustryfroma“ControlArea”toa“Balancing
Area”.Inaddition,itwastellingtheentity"howtodoit"ratherthanallowingtheentityto
performthenecessaryfunctionsinthemosteffectiveandreliablemanner.
Thenewdefinitionreflectsaprocessandallowstheentitytheflexibilitytoperformthe
necessaryfunctioninthemosteffectiveandreliablemannertoaddresssuchprocess
withoutbeinginstructedon"howtodoit".
AutomaticGenerationControl(AGC):Aprocessdesignedandusedtoautomaticallyadjusta
BalancingAuthorityAreas’Demandand/orresourcestohelpmaintaintheReportingACEinthat
ofaBalancingAuthorityAreawithin theboundsrequiredbyapplicableNERCReliability
Standards.
ActualFrequency(FA):TheInterconnectionfrequencymeasuredinHertz(Hz).
ActualNetInterchange(NIA):ThealgebraicsumofactualmegawatttransfersacrossallTie
Lines,includingPseudoͲTies,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection.ActualmegawatttransfersonasynchronousDCtielinesthataredirectly
connectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
ScheduledNetInterchange(NIS):Thealgebraicsumofallscheduledmegawatttransfers,
includingDynamicSchedules,toandfromallAdjacentBalancingAuthorityareaswithinthe
sameInterconnection,includingtheeffectofscheduledramps.Scheduledmegawatttransfers
onasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionareexcludedfrom
ScheduledNetInterchange.
InterchangeMeterError(IME):Aterm,normallyzero,usedintheReportingACEcalculationto
compensatefordataorequipmenterrorsaffectinganyothercomponentsoftheReportingACE
calculation.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page2of18
BALͲ005Ͳ1–BalancingAuthorityControl
AutomaticTimeErrorCorrection(IATEC):TheadditionofacomponenttotheACEequationfor
theWesternInterconnectionthatmodifiesthecontrolpointforthepurposeofcontinuously
payingbackPrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.Automatic
TimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
whenoperatinginAutomaticTimeErrorCorrectionMode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|Bi|andL10,
0.2*|Bi|чLmaxчL10.
x
x
L10ൌ ͳǤͷ כɂଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare
(RMS)valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragiven
year.Thebound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
x
x
Y=Bi/BS.
H=Numberofhoursusedtopaybackprimaryinadvertentinterchangeenergy.Thevalue
ofHissetto3.
x
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
x
x
x
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲBi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontime
monitor,where: ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontime
monitorcontrolcenterclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲ
Peakaccumulationaccountingisrequired,
where:
x
x
x
x
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
ReportingACE:ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError
(ACE)measuredinMWincludesthedifferencebetweentheBalancingAuthorityArea’sActual
NetInterchangeanditsScheduledNetInterchange,plusitsFrequencyBiasSettingobligation,
pluscorrectionforanyknownmetererror.IntheWesternInterconnection,ReportingACE
includesAutomaticTimeErrorCorrection(ATEC).
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page3of18
BALͲ005Ͳ1–BalancingAuthorityControl
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
x NIA
=
ActualNetInterchange.
=
ScheduledNetInterchange.
x NIS
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
x IATEC
=
AutomaticTimeErrorCorrection.
AllNERCInterconnectionsoperateusingtheprinciplesofTieLineTieͲlineBias(TLB)Controland
requiretheuseofanACEequationsimilartotheReportingACEdefinedabove.Any
modification(s)tothisspecifiedReportingACEequationthatis(are)implementedforallBAAs
onanInterconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBias
controlwillprovideavalidalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofall
BAAs’generation,load,andlossisthesameastotalInterconnectiongeneration,load,
andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimes
andthesumofallBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEterm
correctsforknownmeteringorcomputationalerrors.)
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’ReportingACEequation(oralternatecontrolprocesses).
RationaleforModificationofBalancingAuthority:TheSDThasrecommendedtochange
thedefinitionofAutomaticGenerationControl(AGC)andtobeconsistent,withthechange
toAGC,theSDTrecommendschangingthedefinitionofaBalancingAuthority.Inaddition,
Project2015Ͳ04AlignmentofTermsSDTbroughttoourattentionoftheinconsistentuseof
"loadͲinterchangeͲgeneration"andthroughtheAlignmentofTermsprojectitwas
recommendaSDTassociatedwithaBALStandardaddresstheissue.Theproposedchanges
reflectsaBalancingAuthority.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page4of18
BALͲ005Ͳ1–BalancingAuthorityControl
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourcebalancewithinaBalancingAuthorityArea,andsupports
Interconnectionfrequencyinrealtime.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page5of18
BALͲ005Ͳ1–BalancingAuthorityControl
Whenthisstandardhasreceivedballotapproval,thetextboxeswillbemovedtothe
SupplementalMaterialSectionofthestandard.
A. Introduction
1.
Title:
BalancingAuthorityControl
2.
Number:
BALͲ005Ͳ1
3.
Purpose: Thisstandardestablishesrequirementsforacquiringdatanecessaryto
calculateReportingAreaControlError(ReportingACE).Thestandardalsospecifiesa
minimumperiodicity,accuracy,andavailabilityrequirementforacquisitionofthe
dataandforprovidingtheinformationtotheSystemOperator.
4.
Applicability:
4.1. FunctionalEntities:
4.1.1. BalancingAuthority
EffectiveDate: See Implementation Plan for BAL-005-1
B. Requirements and Measures
RationaleforRequirementR1:RealͲtimeoperationofaBalancingAuthorityrequires
realͲtimeinformation.AsufficientscanrateiskeytoanOperator’strustinrealͲtime
information.Withoutasufficientscanrate,anoperatormayquestiontheaccuracyof
dataduringevents,whichwoulddegradetheoperator’sabilitytomaintainreliability.
R1.
TheBalancingAuthorityshalluseadesignscanrateofnomorethansixsecondsin
acquiringdatanecessarytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M1. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthedata
necessarytocalculateReportingACEwasdesignedtobescannedatarateofnomore
thansixseconds.Acceptableevidencemayincludehistoricaldata,datedarchivefiles;
ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR2:TheRCisresponsibleforcoordinatingthereliabilityof
bulkelectricsystemsformemberBA’s.WhenaBAisunabletocalculateitsACEforan
extendedperiodoftime,thisinformationmustbecommunicatedtotheRCwithin15
minutesthereaftersothattheRChassufficientknowledgeofsystemconditionstoassess
anyunintendedreliabilityconsequencesthatmayoccuronthewidearea.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page6of18
BALͲ005Ͳ1–BalancingAuthorityControl
R2.
ABalancingAuthoritythatisunabletocalculateReportingACEformorethan30Ͳ
consecutiveminutesshallnotifyitsReliabilityCoordinatorwithin45minutesofthe
beginningoftheinabilitytocalculateReportingACE.[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]
M2. EachBalancingAuthoritywillhavedatedrecordstoshowwhenitwasunableto
calculateReportingACEformorethan30consecutiveminutesandthatitnotifiedits
ReliabilityCoordinatorwithin45minutesofthebeginningoftheinabilitytocalculate
ReportingACE.Suchevidencemayinclude,butisnotlimitedto,datedvoice
recordings,operatinglogs,orothercommunicationdocumentation.
RationaleforRequirementR3:Frequencyisthebasicmeasurementforinterconnection
health,andacriticalcomponentforcalculatingReportingACE.Withoutsufficient
availablefrequencydatatheBAoperatorwilllacksituationalawarenessandwillbe
unabletomakecorrectdecisionswhenmaintainingreliability.
R3.
EachBalancingAuthorityshallusefrequencymeteringequipmentforthecalculation
ofReportingACE:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]
3.1. thatisavailableaminimumof99.95%foreachcalendaryear;and,
3.2. withaminimumaccuracyof0.001Hz.
M3. TheBalancingAuthorityshallhaveevidencesuchasdateddocumentsorother
evidenceinhardcopyorelectronicformatshowingthefrequencymetering
equipmentusedforthecalculationofReportingACEhadaminimumavailabilityof
99.95%foreachcalendaryearandhadaminimumaccuracyof0.001Hzto
demonstratecompliancewithRequirementR3.
RationaleforRequirementR4:SystemoperatorsutilizeReportingACEasaprimary
metrictodetermineoperatingactionsorinstructions.WhendatainputsintotheACE
calculationareincorrect,theoperatorshouldbemadeawarethroughvisualdisplay.
Whenanoperatorquestionsthevalidityofdata,actionsaredelayedandtheprobability
ofadverseeventsoccurringcanincrease.
R4.
TheBalancingAuthorityshallmakeavailabletotheoperatorinformationassociated
withReportingACEincluding,butnotlimitedto,qualityflagsindicatingmissingor
invaliddata.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtimeOperations]
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page7of18
BALͲ005Ͳ1–BalancingAuthorityControl
M4. EachBalancingAuthorityAreashallhaveevidencesuchasagraphicaldisplayordated
alarmlogthatprovidesindicationofdatavalidityfortherealͲtimeReportingACE
basedonboththecalculatedresultandalloftheassociatedinputstherein.
RationaleforRequirementR5:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.SinceReportingACEisameasureof
theBA’sreliabilityperformanceforBALͲ001,andBALͲ002,itiscriticalthatReportingACE
besufficientlyavailabletoassurereliability.
R5.
EachBalancingAuthority’ssystemusedtocalculateReportingACEshallbeavailablea
minimumof99.5%ofeachcalendaryear.[ViolationRiskFactor:Medium][Time
Horizon:OperationsAssessment]
M5. EachBalancingAuthoritywillhavedateddocumentationdemonstratingthatthe
systemnecessarytocalculateReportingACEhasaminimumavailabilityof99.5%for
eachcalendaryear.Acceptableevidencemayincludehistoricaldata,datedarchive
files;ordatafromotherdatabases,spreadsheets,ordisplaysthatdemonstrate
compliance.
RationaleforRequirementR6:ReportingACEisameasureoftheBA’sreliability
performanceforBALͲ001,andBALͲ002.Withoutaprocesstoaddresspersistenterrorsin
theACEcalculation,theoperatorcanlosetrustinthevalidityofReportingACEresulting
indelayedorincorrectdecisionsregardingthereliabilityofthebulkelectricsystem.
AsuccessfulOperatingProcessmustincludetheabilityforhourlyaccumulatedTieLine
MWHvaluestobeagreedͲuponbetweenBalancingAuthorityAreastoaidinthe
identificationerrorsandassignsucherrorstotheappropriateBalancingAuthorityAreas
formitigationifnecessary.
InstantaneoustielineflowsbetweenBAscannotbeeffectivelycomparedinrealtime.
Methodstoconfirmaccuracyofinstantaneousmeteringisachievedthroughother
means.Theintegrationofinstantaneousmeteredvaluesiscomparedwithaccumulated
MWhvaluestodeterminetheaccuracyof(errorincludedin)theinstantaneousmetering
foreachBA.Thiscomparisonindicatestheaccuracy(amountoferror)foreachBA’sown
instantaneousmeteringascomparedtoitsownaccumulatedMWhmetering.However,
itdoesnotconfirmthattheaccumulatedMWhmeteringforoneBAisequivalenttothe
accumulatedMWhmeteringfortheadjacentBAonthesametieline.Thiscanonlybe
confirmedbycomparingtheaccumulatedMWhvalueforoneBAtotheaccumulated
MWhvaluefortheadjacentBA.Ifthesetwovaluesarethesame,anyproblemwiththe
meteringisidentifiedbythedifferencebetweentheintegratedinstantaneousMWhsand
theaccumulatedMWhforthatBA.However,ifthereisadifferencebetweenthe
accumulatedMWhsbetweenthetwoadjacentBAs,thoseBAsmustagreeupona
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page8of18
BALͲ005Ͳ1–BalancingAuthorityControl
commonvaluetouseforthathourforthattielineinordertoassignresponsibilityfor
managingtheerrorrepresentedbythedifferencebetweentheiraccumulatedvalues.If
theBAsdonotagreeuponavalue,thedifferencebetweentheaccumulatedvalueswill
notbeincludedintheirerrormitigationprocessandthaterrorwillthereforebepassedto
theinterconnectionasafrequencycontrolburden.
R6.
EachBalancingAuthoritythatiswithinamultipleBalancingAuthorityInterconnection
shallimplementanOperatingProcesstoidentifyandmitigateerrorsaffectingthe
accuracyofscanratedatausedinthecalculationofReportingACEforeachBalancing
AuthorityArea.[ViolationRiskFactor:Medium][TimeHorizon:SameͲdayOperations
]
M6. EachBalancingAuthorityshallhaveacurrentOperatingProcessmeetingthe
provisionsofRequirementR6andevidencetoshowthattheprocesswas
implemented,suchasdatedcommunicationsorincorporationinSystemOperator
taskverification.
RationaleforRequirementR7:ReportingACEisanessentialmeasurementoftheBA’s
contributiontothereliabilityoftheInterconnection.Commonsourcedataiscriticalto
calculatingReportingACEthatisconsistentbetweenBalancingAuthorities.Whendata
sourcesarenotcommon,confusioncanbecreatedbetweenBAsresultingindelayedor
incorrectoperatoraction.
TheintentofRequirementR7Part7.1istoprovideaccuracyinthemeasurementand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
instantaneousvaluesfortheTieLinetieͲlinemegawattflowvaluesbetweenBalancing
AuthorityAreas.Commondatasourcerequirementsalsoapplytoinstantaneousvalues
forpseudoͲtiesanddynamicschedules,andcanextendtomorethantwoBalancing
Authoritiesthatparticipateinallocatingsharesofagenerationresourcein
supplementaryregulation,forexample.
TheintentofRequirementR7Part7.2istoenableaccuracyinthemeasurementsand
calculationsusedinReportingACE.Itspecifiestheneedforcommonmeteringpointsfor
hourlyaccumulatedvaluesforthetimesynchronizedtielineMWhvaluesagreedͲupon
betweenBalancingAuthorityAreas.ThesetimesynchronizedagreedͲuponvaluesare
necessaryforuseintheOperatingProcessrequiredinR6toidentifyandmitigateerrors
inthescanratescanͲratevaluesusedinReportingACE.
R7.
EachBalancingAuthorityshallensurethateachTieLineTieͲLine,PseudoͲTie,and
DynamicSchedulewithanAdjacentBalancingAuthorityisequippedwith:[Violation
RiskFactor:Medium][TimeHorizon:OperationsPlanning]
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page9of18
BALͲ005Ͳ1–BalancingAuthorityControl
7.1. acommonsourcetoprovideinformationtobothBalancingAuthoritiesforthe
scanratevaluesusedinthecalculationofReportingACE;and,
7.2. atimesynchronizedcommonsourcetodeterminehourlymegawattͲhourvalues
agreedͲupontoaidintheidentificationandmitigationoferrorsunderthe
OperatingProcessasdevelopedinRequirementR6.
M7. TheBalancingAuthorityshallhavedatedevidencesuchasvoicerecordingsor
transcripts,operatorlogs,electroniccommunications,orotherequivalentevidence
thatwillbeusedtodemonstrateacommonsourceforthecomponentsusedinthe
calculationofReportingACEwithitsAdjacentBalancingAuthority.
C. Compliance
1.
ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliabilityStandards.
1.2. EvidenceRetention
Thefollowingevidenceretentionperiod(s)identifytheperiodoftimean
entityisrequiredtoretainspecificevidencetodemonstratecompliance.For
instanceswheretheevidenceretentionperiodspecifiedbelowisshorterthan
thetimesincethelastaudit,theComplianceEnforcementAuthoritymayask
anentitytoprovideotherevidencetoshowthatitwascompliantforthefullͲ
timeperiodsincethelastaudit.
Theapplicableentityshallkeepdataorevidencetoshowcomplianceas
identifiedbelowunlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
x
Theapplicableentityshallkeepdataorevidencetoshowcompliancefor
thecurrentyear,plusthreepreviouscalendaryears.
1.3. ComplianceMonitoringandAssessmentProcesses:
AsdefinedintheNERCRulesofProcedure,“ComplianceMonitoringand
AssessmentProcesses”referstotheidentificationoftheprocessesthatwill
beusedtoevaluatedataorinformationforthepurposeofassessing
performanceoroutcomeswiththeassociatedReliabilityStandard.
1.4. AdditionalComplianceInformation
None
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page10of18
Medium
Medium
R1. RealͲtime
Operations
R2. RealͲtime
Operations
Draft#3ofStandardBALͲ005Ͳ1:January,2016
VRF
Time
Horizon
R#
Table of Compliance Elements
N/A
Lower VSL
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
45minutesofthe
beginningofa30Ͳ
minutetheinabilityto
calculateReporting
ACEbutnotifiedits
Reliability
Coordinatorwithin
nomorelessthanor
equalto50minutes
fromthebeginningof
theinabilityto
BALͲ005Ͳ1–BalancingAuthorityControl
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin50
minutesofthe
beginningofa30Ͳ
minuteaninabilityto
calculateReporting
ACEbutnotifiedits
Reliability
Coordinatorwithin
nmomorelessthanor
equalto55minutes
fromthebeginningof
aninabilityto
N/A
Moderate VSL
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin
55minutesofthe
beginningofa30Ͳ
minuteaninabilityto
calculateReporting
ACEbutnotifiedits
Reliability
Coordinatorwithin
nomorelessthanor
equalto60minutes
fromthebeginningof
aninabilityto
N/A
High VSL
Violation Severity Levels
Page11of18
TheBalancing
Authorityfailedto
notifyitsReliability
Coordinatorwithin60
minutesofthe
beginningofa30Ͳ
minuteaninabilityto
calculateReporting
ACE.
BalancingAuthority
wasusingadesign
scanrateofgreater
thansixsecondsto
acquirethedata
necessarytocalculate
ReportingACE.
Severe VSL
Medium
R4. RealͲtime
Operations
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Medium
R3. RealͲtime
Operations
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.95%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.94%ofthe
calendaryear.
calculateReporting
ACE.
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.94%ofthe
calendaryearbutwas
availablegreaterthan
orequalto99.93%of
thecalendaryear.
calculateReporting
ACE.
N/A
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.93%ofthe
calendaryearbut
wasavailablegreater
thanorequalto
99.92%ofthe
calendaryear.
calculateReporting
ACE.
Page12of18
TheBalancing
Authorityfailedto
makeavailable
information
indicatingmissingor
invaliddata
associatedwith
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEfailed
tohaveaminimum
accuracyof0.001Hz.
Or
TheBalancing
Authority’sfrequency
meteringequipment
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.92%ofthe
calendaryear
Medium
R7. Operations
Planning
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Medium
R6. SameͲday
Operations
R5. Operations Medium
Assessment
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.5%ofthecalendar
yearbutwas
availablegreater
thanorequalto99.4
%ofthecalendar
year.
BALͲ005Ͳ1–BalancingAuthorityControl
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.4%ofthecalendar
yearbutwas
availablegreaterthan
orequalto99.3%of
thecalendaryear.
N/A
N/A
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.3%ofthecalendar
yearbutwas
availablegreater
thanorequalto99.2
%ofthecalendar
year.
Page13of18
TheBalancing
Authorityfailedto
useacommonsource
forTieLinesTieͲLines,
PseudoͲtiesand
TheBalancing
Authorityfailedto
implementan
OperatingProcessto
identifyandmitigate
errorsaffectingthe
scanratescanͲrate
accuracyofdataused
inthecalculationof
ReportingACE.
TheBalancing
Authority’ssystem
usedforthe
calculationof
ReportingACEwas
availablelessthan
99.2%ofthecalendar
year.
ReportingACEtoits
operators.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
BALͲ005Ͳ1–BalancingAuthorityControl
Page14of18
TheBalancing
Authorityfailedto
useatime
synchronized
commonsourcefor
hourlymegawatt
hourvaluesthatare
agreedͲupontoaidin
theidentificationand
mitigationoferrors.
Or
DynamicSchedules
withitsAdjacent
BalancingAuthorities
February 8,
2005
April 1, 2005
August 8, 2005
December 19,
2007
January 16,
2008
February 12,
2008
October 29,
2008
May 13, 2009
March 8, 2012
September 13,
2012
0
0
0
0a
0a
0b
0.1b
0.1b
0.2b
0.2b
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Date
Version
Version History
Action
FERC approved – Updated Effective Date
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
FERC approved – Updated Effective Date
BOT approved errata changes; updated version
number to “0.1b”
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Removed “Proposed” from Effective Date
Effective Date
Adopted by NERC Board of Trustees
BALͲ005Ͳ1–BalancingAuthorityControl
Addition
Errata
Addition
Errata
Replacement
Errata
Addition
Errata
New
New
Change Tracking
Page15of18
November21,
2013
0.2b
R2andassociatedelementsapprovedby FERC for
retirementaspartoftheParagraph81 project
(Project2013Ͳ02)effectiveJanuary21,2014.
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page16of18
Standards Attachments
NOTE:Usethissectionforattachmentsorotherdocumentsthatarereferencedinthestandardaspartoftherequirements.These
shouldappearaftertheendofthestandardtemplateandbeforetheSupplementalMaterial.Iftherearenone,deletethissection.
February 7,
2013
0.2b
BALͲ005Ͳ1–BalancingAuthorityControl
SupplementalMaterial
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page17of18
SupplementalMaterial
Rationale
UponBoardapproval,thetextfromtherationaleboxeswillbemovedtothissection.
Draft#3ofStandardBALͲ005Ͳ1:January,2016
Page18of18
BAL-005-1 – Balancing Authority Control
A. Introduction
1.
Title:
Automatic Generation Balancing Authority Control
2.
Number:
BAL-005-0.2b1
3.
Purpose: This standard establishes requirements for Balancing Authority
Automatic Generation Control (AGC)acquiring data necessary to calculate Reporting
Area Control Error (Reporting ACE) and to routinely deploy the Regulating Reserve.).
The standard also ensures that all facilitiesspecifies a minimum periodicity, accuracy,
and availability requirement for acquisition of the data and load electrically
synchronized tofor providing the Interconnection are included within information to
the metered boundary of a Balancing Area so that balancing of resources and demand
can be achievedSystem Operator.
4.
Applicability:
1.1. Balancing Authorities
1.2.
Generator Operators
1.3.
Transmission Operators
4.1. Load ServingFunctional Entities:
4.1.1. Balancing Authority
Effective Date:
B.
May 13, 2009 See Implementation Plan for BAL-005-1
Requirements
B. All generation, transmission, and load operating within an Interconnection
must be included within the metered boundaries of a Balancing Authority
Area.Measures
Rationale for Requirement R1: Real-time operation of a Balancing Authority requires
real-time information. A sufficient scan rate is key to an Operator’s trust in real-time
information. Without a sufficient scan rate, an operator may question the accuracy of
data during events, which would degrade the operator’s ability to maintain reliability.
R1.
The Balancing Authority shall Each Generator Operator with generation facilities
operating in an Interconnection shall ensure that those generation facilities are included
within the metered boundaries of a Balancing Authority Area.use a design scan rate of
no more than six seconds in acquiring data necessary to calculate Reporting ACE.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
Draft #3 of Standard BAL-005-1: January, 2016
Page 1 of 13
BAL-005-1 – Balancing Authority Control
M1. Each Balancing Authority will have dated documentation demonstrating that the data
necessary to calculate Reporting ACE was designed to be scanned at a rate of no more
than six seconds. Acceptable evidence may include historical data, dated archive files;
or data from other databases, spreadsheets, or displays that demonstrate
compliance.
Rationale for Requirement R2: The RC is responsible for coordinating the reliability of
bulk electric systems for member BA’s. When a BA is unable to calculate its ACE for an
extended period of time, this information must be communicated to the RC within 15
minutes thereafter so that the RC has sufficient knowledge of system conditions to assess
any unintended reliability consequences that may occur on the wide area.
Each Transmission Operator with transmission facilities operating in an
Interconnection shall ensure that those transmission facilities are included within the
metered boundaries of a Balancing Authority Area.
Each Load-Serving Entity with load operating in an Interconnection shall ensure that those
loads are included within the metered boundaries of a Balancing Authority Area.
R1. Each Balancing Authority shall maintain Regulating Reserve that can be controlled by
AGC to meet the Control Performance Standard. (Retirement approved by NERC
BOT pending applicable regulatory approval.)
R2. A Balancing Authority providing Regulation Service shall ensure that adequate
metering, communications, and control equipment are employed to prevent such
service from becoming a Burden on the Interconnection or other Balancing Authority
Areas.
R2.
. A Balancing Authority providing Regulation Servicethat is unable to calculate
Reporting ACE for more than 30-consecutive minutes shall notify its Reliability
Coordinator within 45 minutes of the beginning of the inability to calculate Reporting
ACE. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
M2. Each Balancing Authority will have dated records to show when it was unable to
calculate Reporting ACE for more than 30 consecutive minutes and that it notified its
Reliability Coordinator within 45 minutes of the beginning of the inability to calculate
Reporting ACE. Such evidence may include, but is not limited to, dated voice
recordings, operating logs, or other communication documentation.
Rationale for Requirement R3: Frequency is the basic measurement for interconnection
health, and a critical component for calculating Reporting ACE. Without sufficient
Draft #3 of Standard BAL-005-1: January, 2016
Page 2 of 13
BAL-005-1 – Balancing Authority Control
available frequency data the BA operator will lack situational awareness and will be
unable to make correct decisions when maintaining reliability.
R3.
Each Balancing Authority shall use frequency metering equipment for the calculation
of Reporting ACE: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
3.1. that is available a minimum of 99.95% for each calendar year; and,
3.2. with a minimum accuracy of 0.001 Hz.
M3. The Balancing Authority shall the Hosthave evidence such as dated documents or
other evidence in hard copy or electronic format showing the frequency metering
equipment used for the calculation of Reporting ACE had a minimum availability of
99.95% for each calendar year and had a minimum accuracy of 0.001 Hz to
demonstrate compliance with Requirement R3.
Rationale for Requirement R4: System operators utilize Reporting ACE as a primary
metric to determine operating actions or instructions. When data inputs into the ACE
calculation are incorrect, the operator should be made aware through visual display.
When an operator questions the validity of data, actions are delayed and the probability
of adverse events occurring can increase.
R1.R4.
The Balancing Authority for whom it is controlling if it is unable to provide the
service, as well as any Intermediate Balancing Authorities.shall make available to the
operator information associated with Reporting ACE including, but not limited to,
quality flags indicating missing or invalid data. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
M4. EachA Balancing Authority Area shall have evidence such as a graphical display or
dated alarm log that provides indication of data validity for the real-time Reporting
ACE based on both the calculated result and all of the associated inputs therein.
Rationale for Requirement R5: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Since Reporting ACE is a measure of
the BA’s reliability performance for BAL-001, and BAL-002, it is critical that Reporting ACE
be sufficiently available to assure reliability.
R1.1.
Draft #3 of Standard BAL-005-1: January, 2016
Page 3 of 13
BAL-005-1 – Balancing Authority Control
R5.
Each Balancing Authority’s system used to calculate Reporting ACE shall be available a
minimum of 99.5% of each calendar year. [Violation Risk Factor: Medium] [Time
Horizon: Operations Assessment]
M5. Each Balancing Authority will have dated documentation demonstrating that the
system necessary to calculate Reporting ACE has a minimum availability of 99.5% for
each calendar year. Acceptable evidence may include historical data, dated archive
files; or data from other databases, spreadsheets, or displays that demonstrate
compliance.
Rationale for Requirement R6: Reporting ACE is a measure of the BA’s reliability
performance for BAL-001, and BAL-002. Without a process to address persistent errors in
the ACE calculation, the operator can lose trust in the validity of Reporting ACE resulting
in delayed or incorrect decisions regarding the reliability of the bulk electric system.
A successful Operating Process must include the ability for hourly accumulated Tie Line
MWH values to be agreed-upon between Balancing Authority Areas to aid in the
identification errors and assign such errors to the appropriate Balancing Authority Areas
for mitigation if necessary.
Instantaneous tie line flows between BAs cannot be effectively compared in real time.
Methods to confirm accuracy of instantaneous metering is achieved through other
means. The integration of instantaneous metered values is compared with accumulated
MWh values to determine the accuracy of (error included in) the instantaneous metering
for each BA. This comparison indicates the accuracy (amount of error) for each BA’s own
instantaneous metering as compared to its own accumulated MWh metering. However,
it does not confirm that the accumulated MWh metering for one BA is equivalent to the
accumulated MWh metering for the adjacent BA on the same tie line. This can only be
confirmed by comparing the accumulated MWh value for one BA to the accumulated
MWh value for the adjacent BA. If these two values are the same, any problem with the
metering is identified by the difference between the integrated instantaneous MWhs and
the accumulated MWh for that BA. However, if there is a difference between the
accumulated MWhs between the two adjacent BAs, those BAs must agree upon a
common value to use for that hour for that tie line in order to assign responsibility for
managing the error represented by the difference between their accumulated values. If
the BAs do not agree upon a value, the difference between the accumulated values will
not be included in their error mitigation process and that error will therefore be passed to
the interconnection as a frequency control burden.
R6.
Each Balancing Authority receiving Regulation Servicethat is within a multiple
Balancing Authority Interconnection shall implement an Operating Process to identify
and mitigate errors affecting the accuracy of scan rate data used in the calculation of
Draft #3 of Standard BAL-005-1: January, 2016
Page 4 of 13
BAL-005-1 – Balancing Authority Control
Reporting ACE for each Balancing Authority Area. [Violation Risk Factor: Medium]
[Time Horizon: Same-day Operations ]
M6. Each Balancing Authority shall have a current Operating Process meeting the
provisions of Requirement R6 and evidence to show that the process was
implemented, such as dated communications or incorporation in System Operator
task verification.
Rationale for Requirement R7: Reporting ACE is an essential measurement of the BA’s
contribution to the reliability of the Interconnection. Common source data is critical to
calculating Reporting ACE that is consistent between Balancing Authorities. When data
sources are not common, confusion can be created between BAs resulting in delayed or
incorrect operator action.
The intent of Requirement R7 Part 7.1 is to provide accuracy in the measurement and
calculations used in Reporting ACE. It specifies the need for common metering points for
instantaneous values for the Tie Line megawatt flow values between Balancing Authority
Areas. Common data source requirements also apply to instantaneous values for pseudoties and dynamic schedules, and can extend to more than two Balancing Authorities that
participate in allocating shares of a generation resource in supplementary regulation, for
example.
The intent of Requirement R7 Part 7.2 is to enable accuracy in the measurements and
calculations used in Reporting ACE. It specifies the need for common metering points for
hourly accumulated values for the time synchronized tie line MWh values agreed-upon
between Balancing Authority Areas. These time synchronized agreed-upon values are
necessary for use in the Operating Process required in R6 to identify and mitigate errors
in the scan rate values used in Reporting ACE.
R7.
Each Balancing Authority shall ensure that backup plans are in placeeach Tie Line,
Pseudo-Tie, and Dynamic Schedule with an Adjacent Balancing Authority is equipped
with: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
R3. a common source to provide replacement Regulation Service should the supplying
Balancing Authority no longer be able to provide this service.
1.1.7.1.
The Balancing Authority’s AGC shall compare total Net Actual
Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to
determine the Balancing Authority’s ACE. Singleinformation to both Balancing
Authorities operating asynchronously may employ alternative ACE calculations
such as (but not limited to) flat frequency control. If a Balancing Authority is
unable to calculate ACE for more than 30 minutes it shall notify its Reliability
Draft #3 of Standard BAL-005-1: January, 2016
Page 5 of 13
BAL-005-1 – Balancing Authority Control
Coordinator.for the scan rate values used in the calculation of Reporting ACE;
and,
7.2. a time synchronized common source to determine hourly megawatt-hour values
agreed-upon to aid in the identification and mitigation of errors under the
Operating Process as developed in Requirement R6.
R4. The Balancing Authority shall operate AGC continuously unlesshave dated evidence
such operation adversely impacts the reliability of the Interconnection. If AGC has
become inoperative, the Balancing Authority shall use manual control to adjust
generation to maintain the Net Scheduled Interchange.
The Balancing Authority shall ensureas voice recordings or transcripts, operator logs,
electronic communications, or other equivalent evidence that data acquisition will be
used to demonstrate a common source for and the components used in the
calculation of Reporting ACE occur at least every six seconds.
R5. Each Balancing Authority shall provide redundant and independent frequency metering
equipment that shall automatically activate upon detection of failure of the primary
source. This overall installation shall provide a minimum availability of 99.95%.
R6. The Balancing Authority shall include all Interchange Schedules with its Adjacent
Balancing Authorities in the calculation of Net Scheduled Interchange for the ACE
equation.
R6.5. Balancing Authorities with a high voltage direct current (HVDC) link to
another Balancing Authority connected asynchronously to their Interconnection
may choose to omit the Interchange Schedule related to the HVDC link from
the ACE equation if it is modeled as internal generation or load.
R7. The Balancing Authority shall include all Dynamic Schedules in the calculation of Net
Scheduled Interchange for the ACE equation.
Balancing Authorities shall include the effect of ramp rates, which shall be identical
and agreed to between affected Balancing Authorities, in the Scheduled Interchange
values to calculate ACE.Authority
R8. Each Balancing Authority shall include all Tie Line flows with Adjacent Balancing
Authority Areas in the ACE calculation.
R8.5. Balancing Authorities that share a tie shall ensure Tie Line MW metering is
telemetered to both control centers, and emanates from a common, agreed-upon
source using common primary metering equipment. Balancing Authorities
shall ensure that megawatt-hour data is telemetered or reported at the end of
each hour.
R8.6. Balancing Authorities shall ensure the power flow and ACE signals that are
utilized for calculating Balancing Authority performance or that are transmitted
for Regulation Service are not filtered prior to transmission, except for the Antialiasing Filters of Tie Lines.
Draft #3 of Standard BAL-005-1: January, 2016
Page 6 of 13
BAL-005-1 – Balancing Authority Control
Balancing Authorities shall install common metering equipment where Dynamic Schedules
or Pseudo-Ties are implemented between two or more Balancing Authorities to deliver
the output of Jointly Owned Units or to serve remote load.
Each Balancing Authority shall perform hourly error checks using Tie Line megawatt-hour
meters with common time synchronization to determine the accuracy of its control
equipment. The Balancing Authority shall adjust the component (e.g., Tie Line meter)
of ACE that is in error (if known) or use the interchange meter error (I ME ) term of the
ACE equation to compensate for any equipment error until repairs can be made.
The Balancing Authority shall provide its operating personnel with sufficient instrumentation
and data recording equipment to facilitate monitoring of control performance,
generation response, and after-the-fact analysis of area performance. As a minimum,
the Balancing Authority shall provide its operating personnel with real-time values for
ACE, Interconnection frequency and Net Actual Interchange with each Adjacent
Balancing Authority Area.
R9. The Balancing Authority shall provide adequate and reliable backup power supplies
and shall periodically test these supplies at the Balancing Authority’s control center
and other critical locations to ensure continuous operation of AGC and vital data
recording equipment during loss of the normal power supply.
R10. The Balancing Authority shall sample data at least at the same periodicity with which
ACE is calculated. The Balancing Authority shall flag missing or bad data for
operator display and archival purposes. The Balancing Authority shall collect
coincident data to the greatest practical extent, i.e., ACE, Interconnection frequency,
Net Actual Interchange, and other data shall all be sampled at the same time.
R11. Each Balancing Authority shall at least annually check and calibrate its time error and
frequency devices against a common reference. The Balancing Authority shall adhere
to the minimum values for measuring devices as listed below:
C.
Device
Accuracy
Digital frequency transducer
d 0.001
MW, MVAR, and voltage transducer
d 0.25 % of full scale
Remote terminal unit
d 0.25 % of full scale
Potential transformer
d 0.30 % of full scale
Current transformer
d 0.50 % of full scale
Hz
Measures
M1.M7.
Not specified.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
Balancing Authorities shall be prepared to supply data to NERC in the format
defined below:
Draft #3 of Standard BAL-005-1: January, 2016
Page 7 of 13
BAL-005-1 – Balancing Authority Control
1.1.1.
Within one week upon request, Balancing Authorities shall provide As
defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Reliability Organization CPS
source data Entity in daily CSV filestheir respective roles of
monitoring and enforcing compliance with time stamped one minute
averages of: 1) ACE and 2) Frequency Error.
Within one week upon request, Balancing Authorities shall provide the NERC
or the Regional Reliability Organization DCS source data in CSV files with
time stamped scan rate values for: 1) ACE and 2) Frequency Error for a time
period of two minutes prior to thirty minutes after the identified
DisturbanceReliability Standards.
1.2.
Compliance Monitoring Period and Reset Timeframe
Not specified.
1.2. DataEvidence Retention
1.3.1. Each Balancing Authority shall retain its ACE, actual frequency,
Scheduled Frequency, Net Actual Interchange, Net Scheduled
Interchange, Tie Line meter error correction and Frequency Bias
Setting data in digital format at the same scan rate at which the data is
collected for at least one year.
1.3.2.
Each Balancing Authority or Reserve Sharing Group shall retain
documentation of the magnitude of each Reportable Disturbance as
well as the ACE charts and/or samples used to calculate Balancing
Authority or Reserve Sharing Group disturbance recovery values. The
data shall be retained for one year following the reporting quarter for
which the data was recorded.
The following evidence retention period(s) identify the period of time an
entity is required to retain specific evidence to demonstrate compliance. For
instances where the evidence retention period specified below is shorter than
the time since the last audit, the Compliance Enforcement Authority may ask
an entity to provide other evidence to show that it was compliant for the fulltime period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
x
The applicable entity shall keep data or evidence to show compliance for
the current year, plus three previous calendar years.
1.3. Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will
be used to evaluate data or information for the purpose of assessing
performance or outcomes with the associated Reliability Standard.
Draft #3 of Standard BAL-005-1: January, 2016
Page 8 of 13
BAL-005-1 – Balancing Authority Control
1.3.1.4. Additional Compliance Information
Not specified.
LevelsNone
Draft #3 of Standard BAL-005-1: January, 2016
Page 9 of 13
Supplemental Material
Table of Non-Compliance Elements
Not specified.
R#
Time
Horizon
VRF
R1.
Real-time
Operations
Medium
R2.
Real-time
Operations
Medium
The Balancing
Authority failed to
notify its Reliability
Coordinator within
45 minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator within
no more than 50
minutes from the
beginning of the
inability to calculate
Reporting ACE.
The Balancing
Authority failed to
notify its Reliability
Coordinator within 50
minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator with mo
more than 55
minutes from the
beginning of an
inability to calculate
Reporting ACE.
The Balancing
Authority failed to
notify its Reliability
Coordinator within
55 minutes of the
beginning of a 30minute inability to
calculate Reporting
ACE but notified its
Reliability
Coordinator with no
more than 60
minutes from the
beginning of an
inability to calculate
Reporting ACE.
T
A
n
C
m
b
m
c
A
R3.
Real-time
Operations
Medium
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.95% of the
calendar year but
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.94% of the
calendar year but was
The Balancing
Authority’s frequency
metering equipment
used for the
calculation of
Reporting ACE was
available less than
99.93% of the
calendar year but
T
A
m
u
c
R
a
Draft #3 of Standard BAL-005-1: January, 2016
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
N/A
N/A
N/A
Page 10 of 13
B
w
s
t
a
n
R
Supplemental Material
was available greater
than or equal to
99.94 % of the
calendar year.
available greater than was available greater
or equal to 99.93 % of than or equal to
the calendar year.
99.92 % of the
calendar year.
9
c
O
T
A
m
u
c
R
t
a
R4.
Real-time
Operations
Medium
N/A
N/A
N/A
T
A
m
i
i
i
a
R
o
R5.
Operations
Assessment
Medium
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.5% of the calendar
year but was
available greater
than or equal to 99.4
% of the calendar
year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.4% of the calendar
year but was
available greater than
or equal to 99.3 % of
the calendar year.
The Balancing
Authority’s system
used for the
calculation of
Reporting ACE was
available less than
99.3% of the calendar
year but was
available greater
than or equal to 99.2
% of the calendar
year.
T
A
u
c
R
a
9
y
R6.
Same-day
Operations
Medium
N/A
N/A
N/A
T
A
i
O
i
e
s
d
Draft #3 of Standard BAL-005-1: January, 2016
Page 11 of 13
Supplemental Material
c
R
R7.
Operations
Planning
Medium
N/A
N/A
N/A
T
A
u
f
t
S
A
A
O
T
A
u
s
c
h
h
a
t
m
D. Regional DifferencesVariances
None.
E. Interpretations
NoneNone identified.
E.F.
Associated Documents
Appendix 1 Interpretation of Requirement R17 (February 12, 2008).
1.
None.
Version History
Version
Date
Action
Change
0
February 8,
2005
Adopted by NERC Board of Trustees
New
0
April 1, 2005
Effective Date
New
Draft #3 of Standard BAL-005-1: January, 2016
Page 12 of 13
Supplemental Material
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
0a
December 19,
2007
Added Appendix 1 – Interpretation of R17 approved
by BOT on May 2, 2007
Addition
0a
January 16,
2008
Section F: added “1.”; changed hyphen to “en dash.”
Changed font style for “Appendix 1” to Arial
Errata
0b
February 12,
2008
Replaced Appendix 1 – Interpretation of R17
approved by BOT on February 12, 2008 (BOT
approved retirement of Interpretation included in
BAL-005-0a)
Replacement
0.1b
October 29,
2008
BOT approved errata changes; updated version
number to “0.1b”
Errata
0.1b
May 13, 2009
FERC approved – Updated Effective Date
Addition
0.2b
March 8, 2012
Errata adopted by Standards Committee; (replaced
Appendix 1 with the FERC-approved revised
interpretation of R17 and corrected standard version
referenced in Interpretation by changing from “BAL005-1” to “BAL-005-0)
Errata
0.2b
September 13,
2012
FERC approved – Updated Effective Date
Addition
0.2b
February 7,
2013
R2 and associated elements approved by NERC
Board of Trustees for retirement as part of the
Paragraph 81 project (Project 2013-02) pending
applicable regulatory approval.
0.2b
November 21,
2013
R2 and associated elements approved by FERC for
retirement as part of the Paragraph 81 project
(Project 2013-02) effective January 21, 2014.
Standards Attachments
NOTE: Use this section for attachments or other documents that are referenced in the standard
as part of the requirements. These should appear after the end of the standard template and
before the Supplemental Material. If there are none, delete this section.
Draft #3 of Standard BAL-005-1: January, 2016
Page 13 of 13
FAC-001-3 — Facility Interconnection Requirements
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Description of Current Draft
This is the second posting of the draft standard for a 45-day formal comment period with an
additional ballot.
Completed Actions
Date
Standards Committee approved SAR for posting
June 10, 2014
SAR posted for comment
July 16, 2014
Standard posted for 45-day comment period and initial ballot
July 30, 2015
Standard posted for a 45-day comment period and successive ballot
November 10, 2016
Anticipated Actions
Date
Final ballot
January – February
2016
NERC Board adoption
February 2016
Draft #3 of Standard FAC-001-3: January, 2016
Page 1 of 12
FAC-001-3 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard.
Term: None
Draft #3 of Standard FAC-001-3: January, 2016
Page 2 of 12
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft #3 of Standard FAC-001-3: January, 2016
Page 3 of 12
FAC-001-3 — Facility Interconnection Requirements
Rationale for Requirement R3.3: Consistent with the Functional Model, there cannot be
an assumption that the entity owning the transmission will be the same entity providing
the BA function. It is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s
metered boundaries, which also serves to facilitate the process of the coordination
between the two entities that will be required under numerous other standards upon the
start of operation. Under 3.3, the Transmission Owner is responsible for confirming that
the party interconnecting has made appropriate provisions with a Balancing Authority to
operate within its metered boundaries.
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing
Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
Rationale for Requirement R4.3: Consistent with the Functional Model, there cannot be
an assumption that the entity owning the generation will be the same entity providing
the BA function. It is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s
metered boundaries, which also serves to facilitate the process of the coordination
between the two entities that will be required under numerous other standards upon the
start of operation. Under 4.3, the Generator Owner is responsible for confirming that the
party interconnecting has made appropriate provisions with a Balancing Authority to
operate within its metered boundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
Draft #3 of Standard FAC-001-3: January, 2016
Page 4 of 12
FAC-001-3 — Facility Interconnection Requirements
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing
Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The applicable Functional Entity shall keep data or evidence to show compliance
as identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Draft #3 of Standard FAC-001-3: January, 2016
Page 5 of 12
FAC-001-3 — Facility Interconnection Requirements
Complaint
1.4. Additional Compliance Information
None
Draft #3 of Standard FAC-001-3: January, 2016
Page 6 of 12
Lower
Long-term
Planning
R1
N/A
Draft #3 of Standard FAC-001-3: January, 2016
VRF
Time
Horizon
R#
Table of Compliance Elements
Lower VSL
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 7 of 12
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Draft #3 of Standard FAC-001-3: January, 2016
R2
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 8 of 12
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Lower
Long-term
Planning
R4
The Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
The Generator Owner
failed to address one
part of Requirement
R4 Part 4.1 through
Part 4.3.
N/A
N/A
Draft #3 of Standard FAC-001-3: January, 2016
Lower
Long-term
Planning
R3
FAC-001-3 — Facility Interconnection Requirements
The Generator Owner
failed to address two
parts of Requirement
R4 Part 4.1 through
Part 4.3.
The Transmission
Owner failed to
address two parts of
Requirement R3 Part
3.1 through Part 3.3.
Page 9 of 12
The Generator Owner
failed to address
Requirement R4 Part
4.1 through Part 4.3.
The Transmission
Owner failed to
address Requirement
R3 Part 3.1 through
Part 3.3.
Draft #3 of Standard FAC-001-3: January, 2016
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
FAC-001-3 — Facility Interconnection Requirements
Page 10 of 12
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 11 of 12
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 12 of 12
FAC-001-3 — Facility Interconnection Requirements
Standard Development Timeline
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
Description of Current Draft
Thisisthesecondpostingofthedraftstandardfora45Ͳdayformalcommentperiodwithan
additionalballot.
Completed Actions
Date
StandardsCommitteeapprovedSARforposting
June10,2014
SARpostedforcomment
July16,2014
Standardpostedfor45Ͳdaycommentperiodandinitialballot
July30,2015
Standardpostedfora45Ͳdaycommentperiodandsuccessiveballot
November10,2016
Anticipated Actions
Date
Finalballot
January–February
2016
NERCBoardadoption
February2016
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 1 of 12
FAC-001-3 — Facility Interconnection Requirements
New or Modified Terms Used in NERC Reliability Standards
Thissectionincludesallnewormodifiedtermsusedintheproposedstandardthatwillbe
includedintheGlossaryofTermsUsedinNERCReliabilityStandardsuponapplicableregulatory
approval.Termsusedintheproposedstandardthatarealreadydefinedandarenotbeing
modifiedcanbefoundintheGlossaryofTermsUsedinNERCReliabilityStandards.Thenewor
revisedtermslistedbelowwillbepresentedforapprovalwiththeproposedstandard.
Term:None
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 2 of 12
FAC-001-3 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-3
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make
Facility interconnection requirements available so that entities seeking to interconnect
will have the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection
requirements for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection
requirements and make them available upon request within 45 calendar days of full
execution of an Agreement to conduct a study on the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is
used to interconnect to the Transmission system. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M2. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements) that it met all requirements in Requirement R2.
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 3 of 12
FAC-001-3 — Facility Interconnection Requirements
RationaleforRequirementR3.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthetransmissionwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under3.3,theTransmissionOwnerisresponsibleforconfirmingthat
thepartyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R3. Each Transmission Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new or materially modified existing interconnections.
3.3. Procedures for confirming with those responsible for the reliability of affected
systems of that new or materially modified transmission Facilities are within a
Balancing Authority Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
RationaleforRequirementR4.3:ConsistentwiththeFunctionalModel,therecannotbe
anassumptionthattheentityowningthegenerationwillbethesameentityproviding
theBAfunction.Itistheresponsibilityofthepartyinterconnectingtomakeappropriate
arrangementswithaBalancingAuthoritytoensureitsFacilitiesarewithintheBA’s
meteredboundaries,whichalsoservestofacilitatetheprocessofthecoordination
betweenthetwoentitiesthatwillberequiredundernumerousotherstandardsuponthe
startofoperation.Under4.3,theGeneratorOwnerisresponsibleforconfirmingthatthe
partyinterconnectinghasmadeappropriateprovisionswithaBalancingAuthorityto
operatewithinitsmeteredboundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 4 of 12
FAC-001-3 — Facility Interconnection Requirements
4.2. Procedures for notifying those responsible for the reliability of affected system(s)
of new interconnections.
4.3. Procedures for confirming with those responsible for the reliability of affected
systems ofthat new or materially modified generation Facilities are within a
Balancing Authority Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented
Facility interconnection requirements addressing the procedures) that it met all
requirements in Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The applicable Functional Entity shall keep data or evidence to show compliance
as identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 5 of 12
FAC-001-3 — Facility Interconnection Requirements
Complaint
1.4. Additional Compliance Information
None
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Page 6 of 12
Lower
Long-term
Planning
R1
N/A
Draft#3ofStandardFACͲ001Ͳ3:January,2016
VRF
Time
Horizon
R#
Table of Compliance Elements
Lower VSL
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and made
them available upon
request, but failed to
update them as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 7 of 12
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
45 calendar days but
less than or equal to 60
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Draft#3ofStandardFACͲ001Ͳ3:January,2016
R2
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
60 calendar days but
less than or equal to 70
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
failed to address
interconnection
requirements for one of
the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
70 calendar days but
less than or equal to 80
calendar days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 8 of 12
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Lower
Long-term
Planning
R4
The Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
The Generator Owner
failed to address one
part of Requirement
R4 Part 4.1 through
Part 4.3.
N/A
N/A
Draft#3ofStandardFACͲ001Ͳ3:January,2016
Lower
Long-term
Planning
R3
FAC-001-3 — Facility Interconnection Requirements
The Generator Owner
failed to address two
parts of Requirement
R4 Part 4.1 through
Part 4.3.
The Transmission
Owner failed to
address two parts of
Requirement R3 Part
3.1 through Part 3.3.
Page 9 of 12
The Generator Owner
failed to address
Requirement R4 Part
4.1 through Part 4.3.
The Transmission
Owner failed to
address Requirement
R3 Part 3.1 through
Part 3.3.
Draft#3ofStandardFACͲ001Ͳ3:January,2016
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
FAC-001-3 — Facility Interconnection Requirements
Page 10 of 12
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 11 of 12
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 12 of 12
FAC-001-2 — Facility Interconnection Requirements
A. Introduction
1.
Title:
Facility Interconnection Requirements
2.
Number:
FAC-001-23
3.
Purpose: To avoid adverse impacts on the reliability of the Bulk Electric System,
Transmission Owners and applicable Generator Owners must document and make Facility
interconnection requirements available so that entities seeking to interconnect will have
the necessary information.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Applicable Generator Owner
4.1.2.1 4.1.2.1 Generator Owner with a fully executed Agreement to conduct a
study on the reliability impact of interconnecting a third party Facility to
the Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
1.
5.
Effective Date: The standard shall become effective on the first day of the first
calendar quarter that is one year after the date that this standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is one
year after the date this standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.
Effective Date: See Implementation Plan for FAC-001-3.
B. Requirements and Measures
R1. R1. Each Transmission Owner shall document Facility interconnection requirements,
update them as needed, and make them available upon request. Each Transmission
Owner’s Facility interconnection requirements shall address interconnection requirements
for: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
1.1. generation Facilities;
1.2. transmission Facilities; and
1.3. end-user Facilities.
M1. M1. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R1.
R2. Each applicable Generator Owner shall document Facility interconnection requirements
and make them available upon request within 45 calendar days of full execution of an
Agreement to conduct a study on the reliability impact of interconnecting a third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to the
Transmission system. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
Page 1 of 8
FAC-001-2 — Facility Interconnection Requirements
M2. Each applicable Generator Owner shall have evidence (such as dated, documented Facility
interconnection requirements) that it met all requirements in Requirement R2.
Rationale for Requirement R3.3: Consistent with the Functional Model, there cannot be
an assumption that the entity owning the transmission will be the same entity providing
the BA function. It is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s
metered boundaries, which also serves to facilitate the process of the coordination
between the two entities that will be required under numerous other standards upon the
start of operation. Under 3.3, the Transmission Owner is responsible for confirming that
the party interconnecting has made appropriate provisions with a Balancing Authority to
operate within its metered boundaries.
R3. Each Transmission Owner shall address the following items in its Facility interconnection
requirements: [Violation Risk Factor: Lower] [Time Horizon: Long- Term Planning]
3.1. Procedures for coordinated studies of new or materially modified existing
interconnections and their impacts on affected system(s).
3.2. Procedures for notifying those responsible for the reliability of affected system(s) of
new or materially modified existing interconnections.
3.3. M3. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing Authority
Area’s metered boundaries.
M3. Each Transmission Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R3.
R4.
Rationale for Requirement R4.3: Consistent with the Functional Model, there cannot be
an assumption that the entity owning the generation will be the same entity providing
the BA function. It is the responsibility of the party interconnecting to make appropriate
arrangements with a Balancing Authority to ensure its Facilities are within the BA’s
metered boundaries, which also serves to facilitate the process of the coordination
between the two entities that will be required under numerous other standards upon the
start of operation. Under 4.3, the Generator Owner is responsible for confirming that the
party interconnecting has made appropriate provisions with a Balancing Authority to
operate within its metered boundaries.
R4. Each applicable Generator Owner shall address the following items in its Facility
interconnection requirements: [Violation Risk Factor: Lower] [Time Horizon: LongTerm Planning]
4.1. Procedures for coordinated studies of new interconnections and their impacts on
affected system(s).
Page 2 of 8
FAC-001-2 — Facility Interconnection Requirements
4.2. Procedures for notifying those responsible for the reliability of affected system(s) of
new interconnections.
4.3. M4. Procedures for confirming with those responsible for the reliability of affected
systems that new or materially modified Facilities are within a Balancing Authority
Area’s metered boundaries.
M4. Each applicable Generator Owner shall have evidence (such as dated, documented Facility
interconnection requirements addressing the procedures) that it met all requirements in
Requirement R4.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances where
the evidence retention period specified below is shorter than the time since the last
audit, the CEA may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
Page 3 of 8
FAC-001-3 — Facility Interconnection Requirements
The applicable Functional Entity shall keep data or evidence to show compliance
as identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Draft #3 of Standard FAC-001-3: January, 2016
Page 4 of 10
Lower
Long-term
Planning
R1
N/A
Draft #3 of Standard FAC-001-3: January, 2016
VRF
Time
Horizon
R#
Table of Compliance Elements
Lower VSL
FAC-001-3 — Facility Interconnection Requirements
OR
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
upon request, but
failed to address
interconnection
requirements for two
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
OR
The Transmission
Owner documented
Facility
interconnection
requirements and
made them available
upon request, but
failed to update them
as needed.
The Transmission
Owner documented
Facility
interconnection
requirements, updated
them as needed, and
made them available
OR
The Transmission
Owner documented
Facility
interconnection
requirements, but
failed to update them
as needed and failed to
make them available
upon request.
High VSL
The Transmission
Owner documented
Facility
interconnection
requirements and
updated them as
needed, but failed to
make them available
upon request.
Moderate VSL
Violation Severity Levels
Page 5 of 10
The Transmission
Owner did not
document Facility
interconnection
requirements.
Severe VSL
Long-term
Planning
Lower
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and
make them available
upon request until
more than 45 calendar
days but less than or
equal to 60 calendar
days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Draft #3 of Standard FAC-001-3: January, 2016
R2
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and
make them available
upon request until
more than 60 calendar
days but less than or
equal to 70 calendar
days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
upon request, but
failed to address
interconnection
requirements for one
of the Facilities as
specified in R1, Parts
1.1, 1.2, or 1.3.
The applicable
Generator Owner
failed to document
Facility
interconnection
requirements and
make them available
upon request until
more than 70 calendar
days but less than or
equal to 80 calendar
days after full
execution of an
Agreement to conduct
a study on the
reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Page 6 of 10
The applicable
Generator Owner failed
to document Facility
interconnection
requirements and make
them available upon
request until more than
80 calendar days after
full execution of an
Agreement to conduct a
study on the reliability
impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
system.
Lower
Long-term
Planning
R4
N/AThe Transmission
Owner failed to
address one part of
Requirement R3 Part
3.1 through Part 3.3.
N/AThe Generator
Owner failed to
address one part of
Requirement R4 Part
4.1 through Part 4.3.
N/A
N/A
Draft #3 of Standard FAC-001-3: January, 2016
Lower
Long-term
Planning
R3
FAC-001-3 — Facility Interconnection Requirements
The applicable
Generator Owner
addressed eitherfailed
to address two parts of
Requirement R4, Part
4.1 orthrough Part 4.2
in its Facility
interconnection
requirements, but did
not address both.3.
The Transmission
Owner addressed
eitherfailed to address
two parts of
Requirement R3, Part
3.1 orthrough Part 3.2
in its Facility
interconnection
requirements, but did
not address both.3.
Page 7 of 10
The applicable
Generator Owner
addressed neitherfailed
to address Requirement
R4, Part 4.1 northrough
Part 4.2 in its Facility
interconnection
requirements.3.
The Transmission
Owner addressed
neitherfailed to address
Requirement R3, Part
3.1 northrough Part 3.2
in its Facility
interconnection
requirements.3.
Draft #3 of Standard FAC-001-3: January, 2016
None.
F. Associated Documents
None.
E. Interpretations
None.
D. Regional Variances
FAC-001-3 — Facility Interconnection Requirements
Page 8 of 10
Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.
Requirement R3:
Originally the Parts of R3, with the exception of the first two bullets, which were added by the
Project 2010-02 drafting team, this list has been moved to the Guidelines and Technical Basis
section to provide entities with the flexibility to determine the Facility interconnection
requirements that are technically appropriate for their respective Facilities. Including them as
Parts of R3 was deemed too prescriptive, as frequently some items in the list do not apply to all
applicable entities – and some applicable entities will have requirements that are not included in
this list.
Each Transmission Owner and applicable Generator Owner should consider the following items
in the development of Facility interconnection requirements:
x
Procedures for requesting a new Facility interconnection or material modification to an
existing interconnection
x
Data required to properly study the interconnection
x
Voltage level and MW and MVAR capacity or demand at the point of interconnection
x
Breaker duty and surge protection
x
System protection and coordination
x
Metering and telecommunications
x
Grounding and safety issues
x
Insulation and insulation coordination
x
Voltage, Reactive Power (including specifications for minimum static and dynamic
reactive power requirements), and power factor control
x
Power quality impacts
x
Equipment ratings
x
Synchronizing of Facilities
x
Maintenance coordination
x
Operational issues (abnormal frequency and voltages)
x
Inspection requirements for new or materially modified existing interconnections
x
Communications and procedures during normal and emergency operating conditions
Page 9 of 10
Application Guidelines
Version History
Version
0
Date
April 1, 2005
1
Action
Effective Date
New
Added requirements for Generator
Owner and brought overall standard
format up to date.
Revision under
Project 2010-07
1
February 9, 2012
Adopted by the Board of Trustees
1
September 19, 2013
A FERC order was issued on
September 19, 2013, approving
FAC-001-1. This standard became
enforceable on November 25, 2013
for Transmission Owners. For
Generator Owners, the standard
becomes enforceable on January 1,
2015.
2
Change
Tracking
Revisions to implement the
recommendations of the FAC FiveYear Review Team.
2
August 14, 2014
Adopted by the Board of Trustees
2
November 6, 2014
FERC letter order issued approving
FAC-001-2.
Revision under
Project 2010-02
Page 10 of 10
Implementation Plan
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Reliability Standard BAL-005-1
R equested Approval
x
BAL-005-1 – Balancing Authority Controls
Requested Retirement
x
BAL-005-0.2b – Automatic Generation Control
x
BAL-006-2 – Inadvertent Interchange - Requirement R3
Prerequisite Approval
x
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (F A ): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NI A ): The algebraic sum of actual megawatt transfers
across all Tie Lines, including Pseudo-Ties, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NI S ): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (I ME ): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (I ATEC ): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
Iࢀࡱ =
Τࢌࢌ ࢋࢇ
PIIࢇࢉࢉ࢛
(ିࢅ)ࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of I ATEC shall not exceed L max .
I ATEC shall be zero when operating in any other AGC mode.
x L max is the maximum value allowed for I ATEC set by each BA between 0.2*|B i | and
L 10 , 0.2*|B i |L max L 10 .
x
x
x
x
x
x
x
x
x
x
x
x
L 10 = 1.65 כȜଵ ඥ(െ10B୧ )(െ10Bୗ ) .
H10 is a constant derived from the targeted frequency bound. It is the targeted root-
mean-square (RMS) value of ten-minute average frequency error based on
frequency performance over a given year. The bound, Ȝ 10 , is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
B i = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
B S = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PII hourly ) is (1-Y) * (II actual - B i
Ʃ7(
II actual is the hourly Inadvertent Interchange for the last hour.
Ʃ7(LVWKHKRXUO\FKDQJHLQV\VWHP7LPH(UURUDVGLVWULEXWHGE\WKH,QWHUFRQQHFWLRQ
time monitor,where: Ʃ7( 7( end hour – TE begin hour – TD adj – (t)*(TE offset )
TD adj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TE offset is 0.000 or +0.020 or -0.020.
PII accum is the Balancing Authority Area’s accumulated PII hourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
BAL-005-1 – Balancing Authority Control
January 2016
2
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
= ࢇ࢙࢚ ࢋ࢘ࢊᇱ ࢙ PIIࢇࢉࢉ࢛
+ PIIࢎ࢛࢘࢟
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NI A í1, S í% ) A í F S ) – I ME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NI A í1, S í% ) A í) S ) – I ME + I ATEC
Where:
x NI A
=
Actual Net Interchange.
x
NI S
=
Scheduled Net Interchange.
x
B
=
Frequency Bias Setting.
x
FA
=
Actual Frequency.
x
FS
=
Scheduled Frequency.
x
I ME
=
Interchange Meter Error.
x
I ATEC
=
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie-line Bias (TLB)
Control and require the use of an ACE equation similar to the Reporting ACE
defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAAs on an Interconnection and is(are) consistent with
the following four principles of Tie Line Bias control will provide a valid alternative
to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency F S for all BAAs at all times; and,
BAL-005-1 – Balancing Authority Control
January 2016
3
4. Excludes metering or computational errors. (The inclusion and use of the I ME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC): A process designed and used to adjust a
Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in
that of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
Pseudo-Tie: A time-varying energy transfer that is updated in Real-time and included in the
Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected Balancing
Authorities’ Reporting ACE equation (or alternate control processes).
Balancing Authority: The responsible entity that integrates resource plans ahead of time,
maintains Demand and resource balance within a Balancing Authority Area, and supports
Interconnection frequency in real time.
Applicable Entities
x
Balancing Authority
Applicable Facilities
x
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
BAL-005-1 – Balancing Authority Control
January 2016
4
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented immediately after BAL-005-1 becomes effective as
reflected in the Implementation Plan for FAC-001-3, and BAL-006-2 Requirement R3 will be
retired concurrently with the effective date for BAL-005-1 . Finally, to ensure proper
coordination with BAL-001-2, approved by the Commission in Order No. 810 issued on April
16, 2015, the following definitions associated with BAL-005-1 will be implemented concurrently
with the effective date for BAL-001-2:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
Effective Dates
Definitions
The definitions of the following terms shall become effective immediately after the
effective date of BAL-001-2 1:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
BAL-005-1
Where approval by an applicable governmental authority is required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
Because the definition of “Reporting ACE” associated with BAL-005-1 will become effective immediately after the
effective date of BAL-001-2, the definition of “Reporting ACE” that was approved by the Commission on April 16,
2015 in Order No. 810 (151 FERC ¶ 61,048) will never go into effect.
1
BAL-005-1 – Balancing Authority Control
January 2016
5
after the effective date of the applicable governmental authorities order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
after the date the standard is adopted by the NERC Board of Trustees’, or as otherwise
provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Automatic Generation Control, Pseudo Tie and Balancing Authority
shall be retired at midnight of the day immediately prior to the effective date of BAL-005-1, in
the jurisdiction in which the new standard is becoming effective.
The existing definitions of Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Meter Error, and Automatic Time Error Correction
shall be retired immediately after the effective date of BAL-001-2. 2
Note that the definition of Reporting ACE that was approved by the Commission in Order No. 810, which will
replace the existing definition of Reporting ACE, will be retired immediately prior to the effective date for the
revised definition of Reporting ACE, as described above. As such, the definition of Reporting ACE approved by the
Commission in Order No. 810 will never go into effect.
2
BAL-005-1 – Balancing Authority Control
January 2016
6
Implementation Plan
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Reliability Standard BAL-005-1
Requested Approval
x
BAL-005-1 – Balancing Authority Controls
Requested Retirement
x
BAL-005-0.2b – Automatic Generation Control
x
BAL-006-2 – Inadvertent Interchange - Requirement R3
Prerequisite Approval
x
FAC-001-3 – Facility Interconnection Requirements
Revisions to Glossary Terms
The following definitions shall become effective when BAL-005-1 becomes effective:
Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).
Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers
across all Tie Lines, including PseudoǦTies, to and from all Adjacent Balancing Authority
areas within the same Interconnection. Actual megawatt transfers on asynchronous DC
tie lines that are directly connected to another Interconnection are excluded from Actual
Net Interchange.
Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority
areas within the same Interconnection, including the effect of scheduled ramps.
Scheduled megawatt transfers on asynchronous DC tie lines directly connected to
another Interconnection are excluded from Scheduled Net Interchange.
Interchange Meter Error (IME): A term used in the Reporting ACE calculation to
compensate for data or equipment errors affecting any other components of the
Reporting ACE calculation.
Automatic Time Error Correction (IATEC): The addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
Iࢀࡱ ൌ
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
ሺିࢅሻࡴכ
when operating in Automatic Time Error Correction Mode.
The absolute value of IATEC shall not exceed Lmax .
IATEC shall be zero when operating in any other AGC mode.
x Lmax is the maximum value allowed for IATEC set by each BA between 0.2*|Bi| and
L10, 0.2*|Bi| Lmax L10 .
x
x
x
x
x
x
x
x
x
x
x
x
L10 ൌ ͳǤͷ כȜଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ .
H10 is a constant derived from the targeted frequency bound. It is the targeted rootmean-square (RMS) value of ten-minute average frequency error based on
frequency performance over a given year. The bound, Ȝ 10, is the same for every
Balancing Authority Area within an Interconnection.
Y = Bi / BS.
H = Number of hours used to payback primary inadvertent interchange energy. The
value of H is set to 3.
Bi = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
BS = Sum of the minimum Frequency Bias Settings for the Interconnection (MW /
0.1 Hz).
Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - Bi * ƩTE/6)
IIactual is the hourly Inadvertent Interchange for the last hour.
ƩTE is the hourly change in system Time Error as distributed by the Interconnection
time monitor,where: ƩTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)
TDadj is the Reliability Coordinator adjustment for differences with Interconnection
time monitor control center clocks.
t is the number of minutes of manual Time Error Correction that occurred during the
hour.
TEoffset is 0.000 or +0.020 or -0.020.
PIIaccum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An On-Peak
and Off-Peak accumulation accounting is required,
where:
BALͲ005Ͳ1–BalancingAuthorityControl
January2016
2
Τࢌࢌࢋࢇ
PIIࢇࢉࢉ࢛
Τࢌࢌࢋࢇ
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙PIIࢇࢉࢉ࢛
PIIࢎ࢛࢘࢟
Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area
Control Error (ACE) measured in MW includes the difference between the Balancing
Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its
Frequency Bias Setting obligation, plus correction for any known meter error. In the
Western Interconnection, Reporting ACE includes Automatic Time Error Correction
(ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA í NIS) í 10B (FA í FS) – IME + IATEC
Where:
x NIA
=
Actual Net Interchange.
x
NIS
=
Scheduled Net Interchange.
x
B
=
Frequency Bias Setting.
x
FA
=
Actual Frequency.
x
FS
=
Scheduled Frequency.
x
IME
=
Interchange Meter Error.
x
IATEC
=
Automatic Time Error Correction.
All NERC Interconnections operate using the principles of Tie-line Bias (TLB)
Control and require the use of an ACE equation similar to the Reporting ACE
defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAAs on an Interconnection and is(are) consistent with
the following four principles of Tie Line Bias control will provide a valid alternative
to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the
sum of all BAAs’ generation, load, and loss is the same as total Interconnection
generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all
times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at
all times;
3. The use of a common Scheduled Frequency FS for all BAAs at all times; and,
BALͲ005Ͳ1–BalancingAuthorityControl
January2016
3
4. Excludes metering or computational errors. (The inclusion and use of the IME
term corrects for known metering or computational errors.)
Automatic Generation Control (AGC):A process designed and used to adjust a
Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in
that of a Balancing Authority Area within the bounds required by applicable NERC
Reliability Standards.
PseudoͲTie:AtimeͲvaryingenergytransferthatisupdatedinRealͲtimeandincludedinthe
ActualNetInterchangeterm(NIA)inthesamemannerasaTieLineintheaffectedBalancing
Authorities’Reporting ACEequation(oralternatecontrolprocesses).
BalancingAuthority:Theresponsibleentitythatintegratesresourceplansaheadoftime,
maintainsDemandandresourcebalancewithinaBalancingAuthorityArea,andsupports
Interconnectionfrequencyinrealtime.
Applicable Entities
x
Balancing Authority
Applicable Facilities
x
N/A
Background
Reliability Standard BAL-005-1 addresses Balancing Authority Reliability-based Controls and
establishes requirements for acquiring data necessary to calculate Reporting Area Control Error
(Reporting ACE). Reliability Standard BAL-005-1 (Balancing Authority Controls) and associated
Implementation Plan was developed in conjunction with FAC-001-3 to ensure that entities with
facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
BALͲ005Ͳ1–BalancingAuthorityControl
January2016
4
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented immediately after BAL-005-1 becomes effective as
reflected in the Implementation Plan for FAC-001-3, and BAL-006-2 Requirement R3 will be
retired concurrently with the effective date for BAL-005-1 . Finally, to ensure proper
coordination with BAL-001-2, approved by the Commission in Order No. 810 issued on April
16, 2015, the following definitions associated with BAL-005-1 will be implemented concurrently
with the effective date for BAL-001-2:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
Effective Dates
Definitions
The definitions of the following terms shall become effective immediately after the
effective date of BAL-001-21:
x
Reporting ACE
x
Actual Frequency
x
Actual Net Interchange
x
Scheduled Net Interchange
x
Interchange Meter Error
x
Automatic Time Error Correction
BAL-005-1
Where approval by an applicable governmental authority is required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
Because the definition of “Reporting ACE” associated with BAL-005-1 will become effective immediately after the
effective date of BAL-001-2, the definition of “Reporting ACE” that was approved by the Commission on April 16,
2015 in Order No. 810 (151 FERC ¶ 61,048) will never go into effect.
1
BALͲ005Ͳ1–BalancingAuthorityControl
January2016
5
after the effective date of the applicable governmental authorities order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, BAL-005-1 and
associated definitions, except the definitions enumerated in the section directly above,
shall become effective on the first day of the first calendar quarter that is twelve months
after the date the standard is adopted by the NERC Board of Trustees’, or as otherwise
provided for in that jurisdiction.
Retirements
BAL-005-0.2b (Automatic Generation Control) shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
BAL-006-2 (Inadvertent Interchange) Requirement R3 shall be retired immediately prior to the
Effective Date of BAL-005-1 (Balancing Authority Controls) in the particular jurisdiction in
which the revised standard is becoming effective.
The existing definitions of Automatic Generation Control, Pseudo Tie and Balancing Authority
shall be retired at midnight of the day immediately prior to the effective date of BAL-005-1, in
the jurisdiction in which the new standard is becoming effective.
The existing definitions of Reporting ACE, Actual Frequency, Actual Net Interchange,
Scheduled Net Interchange, Interchange Meter Error, and Automatic Time Error Correction
shall be retired immediately after the effective date of BAL-001-2.2
Note that the definition of Reporting ACE that was approved by the Commission in Order No. 810, which will
replace the existing definition of Reporting ACE, will be retired immediately prior to the effective date for the
revised definition of Reporting ACE, as described above. As such, the definition of Reporting ACE approved by the
Commission in Order No. 810 will never go into effect.
2
BALͲ005Ͳ1–BalancingAuthorityControl
January2016
6
Implementation Plan
Reliability Standard BAL-006-2
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
N/A
Requested Retirement
x
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Prerequisite Events
x NERC Operating Committee approval of Inadvertent Interchange Guideline1
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-2 will be retired concurrently with the effective date of BAL-005-1 and requisite
approval of Inadvertent Interchange Guideline, as reflected in the “Prerequisite Approvals” and
“Prerequisite Events” sections above.
Effective Dates
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.
1
BAL-006-2 shall be retired on the effective date of BAL-005-1 and the approval of Inadvertent
Interchange Guideline.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
November2015
2
Implementation Plan
Reliability Standard BAL-006-23
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
N/ABAL-006-3 – Inadvertent Interchange
Requested Retirement
x
BAL-006-2 – Inadvertent Interchange
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Prerequisite Events
x NERC Operating Committee approval of Inadvertent Interchange Guideline1
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, BAL-006-23 will be retiredimplemented concurrently with the effective date of BAL-0051 and requisite approval of Inadvertent Interchange Guideline, as reflected in the “Prerequisite
Approvals” and “Prerequisite Events” sections above.
Effective Dates
Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the
purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements.
Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.
1
BAL-006-23 shall become effective retired on the effective date of BAL-005-1 and the approval
of Inadvertent Interchange Guideline.
Retirements
BAL-006-2 (Inadvertent Interchange) shall be retired immediately prior to the Effective Date of
BAL-006-3 (Inadvertent Interchange) in the particular jurisdiction in which the revised
standard is becoming effective.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
NovemberJuly2015
2
Implementation Plan
Reliability Standard FAC-001-3
Project 2010-14.2.1 Balancing Authority Reliability-based Controls
Requested Approval
x
FAC-001-3 – Facility Interconnection Requirements
Requested Retirement
x
FAC-001-2 – Facility Interconnection Requirements
Prerequisite Approval
x
BAL-005-1 – Balancing Authority Controls
Revisions to Glossary Terms
x
None
Applicable Entities
x
Balancing Authority
Background
Reliability Standard FAC-001-3 addresses Facility Interconnection Requirements, which ensure
the avoidance of adverse impacts on the reliability of the Bulk Electric System by requiring
Transmission Owners and applicable Generator Owners to document and make Facility
interconnection requirements available so that entities seeking to interconnect will have
necessary information. Reliability Standard FAC-001-3 and associated Implementation Plan was
developed in conjunction with BAL-005-1 (Balancing Authority Controls) to ensure that entities
with facilities and Load operating in an Interconnection are within a Balancing Authority Area’s
metered boundaries. This coordination will allow for the collection of data necessary to calculate
Reporting Area Control Error (Reporting ACE) to achieve the best results under BAL-005-1.
General Considerations
To guarantee proper coordination as intended by the standard drafting team for Project 201014.2.1, FAC-001-3 will be implemented concurrently with BAL-005-1, as reflected in the
“Prerequisite Approvals” section above.
Effective Dates
FAC-001-3 shall become effective on the effective date of BAL-005-1.
Retirements
FAC-001-2 (Facility Interconnection Requirements) shall be retired immediately prior to the
Effective Date of FAC-001-3 (Facility Interconnection Requirements) in the particular
jurisdiction in which the revised standard is becoming effective.
FACͲ001Ͳ3–FacilityInterconnectionRequirements
November2015
2
CalculatingandUsingReportingACEinaTieLineBiasControlProgram
Introduction:
TieLineBias1(TLB)controlhasbeenusedasthepreferredcontrolmethodinNorthAmericafor75years.Inthe
early1950’sthetermAreaControlError(ACE)wasdevelopedforthespecificimplementationofcoordinatedTie
LineBiascontrolnowinusethroughouttheworld.Thisdocumentprovidesresponsibleentitiesguidelinesfor
usingbothrequiredspecificsandthebestpracticesforcalculatingandusingReportingACE2incoordinationwith
othermeasurestoprovidereliablefrequencycontrol.Whiletheincorporationofthesebestpracticesisstrictly
voluntary;reviewing,revising,ordevelopingaprocessusingthesepracticesishighlyencouragedtopromote
andachievereliabilityfortheBulkElectricSystem.
ThefollowingdefinitionsareincludedintheNERCGlossary:
Definition:
5/11/2015
ActualFrequency
FA
TheInterconnectionfrequencymeasuredinHertz(Hz).
Definition:
5/11/2015
ActualNetInterchange
NIA
ThealgebraicsumofactualmegawatttransfersacrossallTieLines,includingPseudoͲTies,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection.ActualmegawatttransfersonasynchronousDC
tielinesdirectlyconnectedtoanotherInterconnectionareexcludedfromActualNetInterchange.
1
2
CapitalizedtermsholdthesamedefinitionasintheNERCglossarythroughoutthisdocument.
TheCPS1measurewasamongthefirstoftheresultsbasedmeasuresdevelopedbyNERC.Itdefinednothowtoperform
control,butinsteaddefinedthetargetcontrolresultsthatweretobeachieved,andamethodtomeasurewhetherornot
thatdefinedcontroltargethadbeenmet.Asaresult,whenCPS1wasimplemented,theACEEquationusedinthat
measurewasalsospecifiedwithinthatstandard.
Historically,AreaControlError(ACE)hasbeenusedtodescribemanytermsinvolvedinTLBControl.WithinaBAA’s
AutomaticGenerationControl(AGC)algorithmtheremaybemorethanoneACEvalueinuse.Insomesystems,theACE
isfilteredpriortodeterminingcontrolactionsinordertosmooththecontrolsignals;or,theremaybeadditional“feedͲ
forward”termsaddedtoACEinanticipationoffuturechanges(e.g.anticipatedramps,changesinambientlightat
sunriseorsunset).TheremaybegaintermsthatmodifycertainvariablessuchastheFrequencyBiasSettingtoimprove
thequalityofcontrolforthespecificcharacteristicsofthatparticularBAA.
SomeauditorshaveraisedcomplianceissuerelatedtotheuseofsuchmodificationstotheACEusedwithintheLoadͲ
FrequencyControl(LFC)system(alsoreferredtoasAGC)andrequiredchangesintheAGCsystemtoconformtothe
definitionofACEinBALͲ001.Theterm“ReportingACE”wasdevelopedandisusedinplaceofthetermACEtoprovidea
consistentperformancemeasurementusingReportingACEandtoremoveanyunnecessaryrestrictionsonthe
specificationofACEwithintheLFCsystem.
1
2
Definition:
AutomaticTimeErrorCorrection
IATEC 5/11/2015
TheadditionofacomponenttotheACEequationfortheWesternInterconnectionthatmodifiesthecontrol
pointforthepurposeofcontinuouslypayingbackprimaryInadvertentInterchange(PII)tocorrect
accumulatedtimeerror.AutomaticTimeErrorCorrectionisonlyapplicableintheWesternInterconnection.
Τࢌࢌࢋࢇ
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ࡵ܂ۯ۳۱
ሺି܇ሻכ۶
whenoperatinginAutomaticTimeErrorCorrectionmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
x
x
x
x
x
x
x
x
x
x
x
x
x
x
LmaxisthemaximumvalueallowedforIATECsetbyeachBAAbetween0.2*|Bi|andL10,0.2*|Bi|LmaxL10.
L10ൌ ͳǤͷ ߝ כଵ ඥሺെͳͲ୧ ሻሺെͳͲୗ ሻ.
H10isaconstantderivedfromthetargetedfrequencybound.ItisthetargetedrootͲmeanͲsquare(RMS)
valueoftenͲminuteaveragefrequencyerrorbasedonfrequencyperformanceoveragivenyear.The
bound,H10,isthesameforeveryBalancingAuthorityAreawithinanInterconnection.
Y=Bi/BS.
H=NumberofhoursusedtopaybackprimaryInadvertentInterchangeenergy.ThevalueofHissetto3.
Bi=FrequencyBiasSettingfortheBalancingAuthorityArea(MW/0.1Hz).
BS=SumoftheminimumFrequencyBiasSettingsfortheInterconnection(MW/0.1Hz).
PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactual–Bi*ȴTE/6)
IIactualisthehourlyInadvertentInterchangeforthelasthour.
ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor,
where:
ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)
TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnectiontimemonitorcontrol
centerclocks.
tisthenumberofminutesofmanualTimeErrorCorrectionthatoccurredduringthehour.
TEoffsetis0.000or+0.020orͲ0.020.
PIIaccumistheBalancingAuthorityArea’saccumulatedPIIhourlyinMWh.AnOnͲPeakandOffͲPeak
accumulationaccountingisrequired,
where:
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
Definition:
FrequencyBiasSetting
B
4/1/2015
Anumber,eitherfixedorvariable,usuallyexpressedinMW/0.1Hz,includedinaBalancingAuthority’sArea
ControlErrorequationtoaccountfortheBalancingAuthorityArea’sinverseFrequencyResponsecontribution
totheInterconnection,anddiscourageresponsewithdrawalthroughsecondarycontrolsystems.
3
Definition:
5/11/2015
InterchangeMeterError
IME
Aterm,normallyzero,usedintheReportingACEcalculationtocompensatefordataorequipmenterrors
affectinganyothercomponentsoftheReportingACEcalculation.
Definition:
ReportingACE
RACE 5/11/2015
ThescanratevaluesofaBalancingAuthorityArea’s(BAA)AreaControlError(ACE)measuredinMWincludes
thedifferencebetweentheBalancingAuthorityArea’sActualNetInterchangeanditsScheduledNet
Interchange,plusitsFrequencyBiasSettingobligation,pluscorrectionforanyknownmetererror.Inthe
WesternInterconnection,ReportingACEincludesAutomaticTimeErrorCorrection(ATEC).
ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME
ReportingACEiscalculatedintheWesternInterconnectionasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)–IME+IATEC
Where:
=
ActualNetInterchange.
x NIA
x NIS
=
ScheduledNetInterchange.
x B
=
FrequencyBiasSetting.
x FA
=
ActualFrequency.
x FS
=
ScheduledFrequency.
x IME
=
InterchangeMeterError.
=
AutomaticTimeErrorCorrection.
x IATEC
AllNERCInterconnectionswithmultipleBalancingAuthorityAreasoperateusingtheprinciplesofTieͲlineBias
(TLB)ControlandrequiretheuseofanACEequationsimilartotheReportingACEdefinedabove.Any
modification(s)tothisspecifiedReportingACEequationthatis(are)implementedforallBAAsonan
Interconnectionandis(are)consistentwiththefollowingfourprinciplesofTieLineBiascontrolwillprovidea
validalternativetothisReportingACEequation:
1. AllportionsoftheInterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’
generation,load,andlossisthesameastotalInterconnectiongeneration,load,andloss;
2. ThealgebraicsumofallBAAs’ScheduledNetInterchangeisequaltozeroatalltimesandthesumof
allBAAs’ActualNetInterchangevaluesisequaltozeroatalltimes;
3. TheuseofacommonScheduledFrequencyFSforallBAAsatalltimes;and,
4. Excludesmeteringorcomputationalerrors.(TheinclusionanduseoftheIMEtermcorrectsforknown
meteringorcomputationalerrors.)
4
Definition:
3/16/2007
ScheduledFrequency
FS
60.0Hz,exceptduringamanualTimeErrorCorrection.
Definition:
5/11/2015
ScheduledNetInterchange
NIS
Thealgebraicsumofallscheduledmegawatttransfers,includingDynamicSchedules,withallAdjacent
BalancingAuthorityareaswithinthesameInterconnection,includingtheeffectofscheduledramps.
ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromScheduledNetInterchange.
Structure:
TheeffectiveuseofReportingACEwithinaTLBcontrolprogramshouldaddressthefollowingcomponents:
(I)
(II)
(III)
(IV)
(V)
(VI)
(VII)
(VIII)
ManagementRolesandExpectations
InformationTechnologyRoles
SystemOperatorRoles
ManualSourceDataEntry
AutomaticallyCollectedSourceData
UsesofReportingACE
HistoricDataManagement
SpecialConditionsandCalculations
Eachindividualcomponentshouldaddressprocessesandprocedures,evaluationofanyissuesorproblems
alongwithsolutions,testing,training,andcommunications.Theseprovisionsandactivitiestogetherwillbe
referredtoastheTieLineBiascontrolprogram.
EachresponsibleentityshouldevaluateallofitsusesforReportingACEinitsoperationsanditsreliability
measurement.ReportingACEisoneofthemostimportantsinglemeasurementsavailabletoindicatethe
currentstateoftheResponsibleEntity’scontributiontointerconnectionreliability.3ReportingACEisalsoused
asanintegralpartofthemeasurementsusedinBALͲ001andBALͲ002.Technicalrequirementsassociatedwith
theparametersusedinthecalculationofReportingACEarespecifiedinBALͲ003andBALͲ005.
I.
ManagementRolesandExpectations
ManagementplaysanimportantroleinmaintaininganeffectiveTLBcontrolprogram.The
managementroleandexpectationsbelowprovideahighͲleveloverviewofthecoremanagement
responsibilitiesrelatedtoeachTieLineBiascontrolprogram.Themanagementofeachresponsible
entityshouldtailortheserolesandexpectationstofitwithinitsownstructure.
a. Setexpectationsforsafety,reliability,andoperationalperformance.
3
WhenconfiguredwithaFrequencyBiasSettingequaltotheactualFrequencyResponseoftheBAA,ReportingACEwill
reflecttheBAA’sobligationtomatchitsactualinterchange,lesstheimpactfromitscurrentFrequencyResponseoffset,
toitsscheduledinterchange.
5
b.
c.
d.
e.
II.
AssurethataTLBcontrolprogramexistsforeachresponsibleentityandiscurrent.
ProvideannualtrainingontheTLBcontrolprogramanditspurposeandrequirements.
EnsuretheproperexpectationofTLBcontrolprogramperformance.
Shareinsightsacrossindustryassociations.
InformationTechnology(IT)Roles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEandsourceinformationarealwayscurrentandcorrect.
c. ImplementtheTLBcontrolprograminRealͲtime.
d. EnsurethattheEMSsupportsthemanualdataentryofallsourcedatarequiredtobeenteredbyIT
staff,systemoperationsstaff,andSystemOperatorsandproperlymanagesthatdataonceentered.
e. EnsurethattheEMSsupportsandmanagestheautomaticcollectionofallsourcedatathatis
requiredtobemeasuredinrealͲtimethroughtelemetryanddataexchangeincludingdataquality
informationtoindicatedatavalidity.
f. EnsurethattheprogramsthatmanagedatausedtocalculatecomponentsofReportingACE,
ReportingACEitself,andsubsequentmeasuresbasedonReportingACEareuptodateandcorrect
asidentifiedby,butnotlimitedtothefollowingcalculationsandequations:
1) ActualNetInterchange4(NIA):
AllBAAsinvolvedaccountforthepowerexchangeandassociatedtransmissionlossesasactual
interchangebetweentheBAAs,bothintheirACEandReportingACEequationsandthroughout
alloftheirenergyaccountingprocesses.
i. Calculateforeachscan.5
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
4
Bydefinition“ActualmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherInterconnectionare
excludedfromActualNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielinesconnectedto
anotherinterconnectionisprovidedin“SpecialConditionsandCalculations”sectionofthisdocument.
5
ActualNetInterchangescanͲratevaluesarealsousedasoneoftheprimaryinputstothecalculationofFrequency
ResponseMeasure(FRM)onFRSForm1andFRSForm2.
6
2) ScheduledNetInterchange6(NIS):
i. Calculateforeachscan.
ii. Integratedhourlyaveragecalculatedforeachhourasanintegrationofthescanratevalues.
(Thisvaluediffersfromtheblockaccountingvalue.)
Note: DynamicSchedulesaretobeaccountedforasInterchangeSchedulesbythesource,
sink,andcontractintermediaryBAA(s),bothintheirrespectiveACEandReportingACE
equations,andthroughoutalloftheirenergyaccountingprocesses.
3) FrequencyError('F=(FA–FS)):
i. Calculateforeachscan.
ii. CalculateclockͲminuteaveragefromvalidsamplesavailablewithineachclockͲminute7
whereatleasthalfofthescanͲratesamplesarevalid.
4) FrequencyTriggerLimit–Low(FTLLow)8:
CalculatetheFrequencyTriggerLimit–LowforeachclockͲminutewhereatleasthalfofthescan
ratesamplesarevalidbysubtractingthreetimesEpsilon1fromtheScheduledFrequency(FS).
5) FrequencyTriggerLimit–High(FTLHigh)9:
CalculatetheFrequencyTriggerLimit–HighforeachclockͲminutewhereatleasthalfofthe
scanratesamplesarevalidbyaddingthreetimesEpsilon1totheScheduledFrequency(FS).
6) AccumulatedprimaryInadvertentInterchange(PII):CalculatedeachhourforWECCBAAsonly.
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ൌ ࢇ࢙࢚ࢋ࢘ࢊᇱ ࢙
ࡼࡵࡵ
Τࢌࢌࢋࢇ
ࢇࢉࢉ࢛
ࡼࡵࡵ
ࢎ࢛࢘࢟
7) AutomaticTimeErrorCorrection(IATEC):CalculateforeachhourforWECCBAAsonlyfor
inclusionintheACEandReportingACEEquationforthenexthour.
Τࢌࢌࢋࢇ
ࡵ܂ۯ۳۱
ࡼࡵࡵࢇࢉࢉ࢛
ൌ
ሺିࢅሻࡴכ
whenoperatinginATECmode.
TheabsolutevalueofIATECshallnotexceedLmax.
IATECshallbezerowhenoperatinginanyotherAGCmode.
6
Bydefinition“ScheduledmegawatttransfersonasynchronousDCtielinesdirectlyconnectedtoanotherinterconnection
areexcludedfromScheduledNetInterchange.”AdditionalinformationonasynchronouslyconnectedDCtielines
connectedtoanotherinterconnectionisprovidedinthe“SpecialConditionsandCalculations”sectionofthisdocument.
7
ClockͲminuteaveragesareusedforthecalculationofACEandFrequencyErrorinCPS1andBAALtoeliminatethe
transientvariationsoftieͲlineflowsandfrequencyerrorusedinthecalculationofperformancemeasures.TheoneͲ
minuteperiodwaschosenbecauseitisevenlydivisiblebyallwholeͲsecondscanrateslessthanthemaximumspecified
scanrateofsixseconds.ThisassuresgreatercomparabilityofperformancedataamongBAswithdifferentscanrates.
8
Thisvariablecouldbeenteredmanuallyaslongasitischangedeverytimeamanualtimeerrorcorrectionisstartedor
stopped.Ifmanualtimeerrorcorrectioniseliminated,itcouldbecomeaconstantandenteredmanually.
7
8) ReportingACE:
i. Calculateforeachscan.
ii. CalculatedaverageforeachclockͲminuteforBAAsusingafixedFrequencyBiasSetting
whenatleasthalfofthevaluesarevalid.9
9) ComplianceFactor10:
i. CalculateforeachscanwherebothReportingACEandFrequencyErrorarevalid.
ii. CalculateforeachclockͲminutewhereboththeaverageclockͲminuteFrequencyErrorand
theaverageclockͲminuteReportingACEarevalid.11
10) ClockͲhourcompliancefactor8:
CalculateforeachhourbysummingthevalidclockͲminutecompliancefactorsforthehourand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthehour.
11) Monthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthemonthanddividingby
thenumberofvalidclockͲminutecompliancefactorsinthemonth.
12) 12Ͳmonthcompliancefactor8:
CalculatebysummingthevalidclockͲminutecompliancefactorsinthe12Ͳmonthperiodand
dividingbythenumberofvalidclockͲminutecompliancefactorsinthe12Ͳmonthperiod.
13) CPS1compliancefactor:
CalculatetheCPS1compliancefactorbydividingthe12Ͳmonthcompliancefactorbythesquare
oftheEpsilon1valuefortheInterconnection.
14) CPS1:
i. CalculatetheCPS1scanrateperformancebydividingthescanratecompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachscanwitha
validcompliancefactor.
ii. CalculatetheCPS1clockͲminuteperformancebydividingtheclockͲminutecompliance
factorbythesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthat
valuefrom2andmultiplyingtheresultby100toconverttoapercentageperformancefor
eachclockͲminutewithavalidcompliancefactor.
iii. CalculatetheCPS1clockͲhourperformancebydividingtheclockͲhourcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
9
TheaverageofthevalueoftheratioofthescanratevalueofReportingACEdividedbythescanratevalueofͲ10times
theFrequencyBiasSettingforthoseBAsusingavariableFrequencyBiasSetting,whereatleasthalfoftheratiovalues
arevalid.
10
UsedforCPS1.
11
ThecompliancefactoriscalculatedwhentheaverageofthevalueoftheratioofthescanratevalueofReportingACE
dividedbythescanratevalueofͲ10timestheFrequencyBiasSettingforthoseBAsusingavariableFrequencyBias
Setting,whereatleasthalfoftheratiovaluesarevalidandtheaverageclockͲminuteFrequencyErrorisvalid.
8
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
iv. CalculatetheCPS1monthlyperformancebydividingthemonthcompliancefactorbythe
squareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2and
multiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲminute
withavalidcompliancefactor.
v. CalculatetheCPS112Ͳmonthperformancebydividingthe12Ͳmonthcompliancefactorby
thesquareoftheEpsilon1valuefortheinterconnectionandsubtractingthatvaluefrom2
andmultiplyingtheresultby100toconverttoapercentageperformanceforeachclockͲ
minutewithavalidcompliancefactor.
15) BalancingAuthorityACELimitͲLow(BAALLow):
i. CalculatethescanrateBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Lowbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
16) BalancingAuthorityACELimitͲHigh(BAALHigh):
i. CalculatethescanrateBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheFrequencyError.
ii. CalculatetheclockͲminuteBalancingAuthorityACELimit–Highbymultiplyingthreetimes
Epsilon1squaredfortheinterconnectionbyͲ10timestheFrequencyBiasSettingand
dividingtheresultbytheclockͲminuteFrequencyErrorwhenatleasthalfofthevaluesare
valid.
17) BalancingAuthorityACELimitͲLowCompliance:
i. AlarmBAALLowpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisbelowtheclockͲminuteBAALLow.
ii. IndicateBAALLownonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
belowtheclockͲminuteBAALLowformorethan30ͲconsecutiveclockͲminutes.
18) BalancingAuthorityACELimitͲHighCompliance:
i. AlarmBAALHighpotentialnonͲcomplianceforeachperiodasdeterminedforoperations
wheretheclockͲminuteReportingACEisabovetheclockͲminuteBAALHigh.
ii. IndicateBAALHighnonͲcomplianceforeachperiodwheretheclockͲminuteReportingACEis
abovetheclockͲminuteBAALHighformorethan30consecutiveclockminutes.
g. EnsurethattheEMSsupportstheretentionofallhistoricdataincludingdataqualityinformation
requiredtoberetainedtosupportcontinuingoperationsandauditrequirements.
9
h. EnsurethattheEMSsupportsandmanagesthepresentationofallinformationrequiredtobe
availabletotheSystemOperatorforrealͲtimeoperations,operationsstaffforevaluationof
operations,andauditorsforcomplianceconfirmation.
i.
ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
III.
SystemOperatorandOperationsStaffRoles
a. ParticipateinappropriateTLBcontrolrelatedtraining.
b. EnsuretheReportingACEinformationisalwayscurrentandcorrect.
c. ConductanevaluationoftheeffectivenessoftheTLBcontrolprogramandincorporatelessons
learned.
d. ImplementtheTLBcontrolprograminRealͲtime.
IV.
ManualSourceDataEntry
ReportingACEiscalculatedinRealͲtime,atleasteverysixseconds12,bytheResponsibleEntity’sEnergy
ManagementSystem(EMS),andmaybepartiallybasedonsourcedatamanuallyenteredintothat
system.Thefollowingsourcedatamaybeentered:
NIA(ActualNetInterchange):Thetelemetryvaluesofactualtieflows,includingpseudoͲties,between
AdjacentBalancingAuthorityAreasmaynotbeavailablefromanautomaticcollectionsource,
requiringmanualentryofestimatedflows.Thesemanualentriesshouldbeperformedina
mannerthatreasonablyassuresequalmagnitudeandoppositesignvaluesareusedbythe
AdjacentBalancingAuthorityAreasenteringthemanualdata.Iftheactualflowestimatesare
thesamefortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedto
thetwoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failureto
matchactualflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
NIS(ScheduledNetInterchange):Thepowertransferschedules,includingtheschedulerampswhere
applicable,areprocessedbytheEMS.Ifscheduledflowestimatesareequalandhaveopposite
signsfortheAdjacentBalancingAuthorityAreas,theeffectofanyerrorswillbeconfinedtothe
twoAdjacentBalancingAuthorityAreasresponsibleforthemanualentries.Failuretomatch
scheduledflowestimateswillresultinerrorsthataffectotherBAAsontheInterconnection.
B(FrequencyBiasSetting):TheFrequencyBiasSetting,orminimumrequiredvalue,fortheBalancing
AuthorityAreaisspecifiedbycalculationsperformedaspartofcompliancewithBALͲ003Ͳ1Ͳ
FrequencyResponseandFrequencyBiasSetting;
R2.
EachBalancingAuthorityAreathatisamemberofamultipleBalancingAuthority
AreaInterconnectionandisnotreceivingOverlapRegulationServiceandusesafixed
FrequencyBiasSettingshallimplementtheFrequencyBiasSettingdeterminedin
accordancewithAttachmentA,asvalidatedbytheERO,intoitsAreaControlError
12
BALͲ005Ͳ1BalancingAuthorityControlͲR2.TheBalancingAuthorityshallusenogreaterthanasixͲsecondscanratein
acquiringdatanecessarytocalculateReportingACE.
10
(ACE)calculationduringtheimplementationperiodspecifiedbytheEROandshall
usethisFrequencyBiasSettinguntildirectedtochangebytheERO.13
10isthefactor(100.1Hz/Hz)thatconvertstheFrequencyBiasSettingunitstoMW/Hz.
FS(ScheduledFrequency):ScheduledFrequency,normally60Hz,ismanuallyadjustedonacoordinated
basiswhendirectedtodosobytheInterconnectionTimeMonitorasspecifiedinBALͲ004Ͳ0.14It
isimportantforallBAAsonaninterconnectiontomaketheseadjustmentsonacoordinated
basissothatallBAAsarecontrollingtothesameScheduledFrequencyatalltimes.
IME(InterchangeMeterError):Thisterm,normallyzero,isavailableforusebytheSystemOperatoror
operationsstafftoaddacorrectiontermintheReportingACEcalculationtocompensatefor
dataorequipmenterrorsaffectinganyothercomponentsidentifiedbyanalysisofhistoricdata
demonstratingtheexistenceoferrors,usuallyerrorsbetweenintegratedhourlyscanͲratedata
andhourlyagreedtoaccumulatedmeterdata.(SeetheSpecialConditionsandCalculations
sectionofthisdocumentforadditionalinformation)
LmaxisthemaximumvalueallowedforIATECsetbyeachBAbetween0.2*|B|andL10,0.2*|B|чLmaxчL10.
YisnormallycalculatedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.
Hisnormallysetto3andusedbytheATECprogramintheEMSforBAsontheWestern
Interconnection.Itrepresentsthenumberofhoursoverwhichtheprimaryinadvertent
interchangeispaidback.
BSisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Itrepresentsthe
sumoftheminimumFrequencyBiasSettingsforallBAAsontheInterconnection.
ȴTEisusedbytheATECprogramintheEMSforBAAsontheWesternInterconnection.Insomecases,it
maybecalculatedbytheEMSbasedonthefactorsintheȴTEequation.ȴTEisthehourly
changeinsystemTimeErrorasdistributedbytheInterconnectiontimemonitor.
TDadjisanadjustmentforthedifferencesbetweenthelocalclockinthelocaltimestandardandthe
InterconnectiontimemonitorcontrolcenterclockssothatthelocalEMScancalculatethe
correctȴTEfortheBAAsandusedbytheATECprogramintheEMSforBAAsontheWestern
Interconnection.
TEoffsetisenteredasinstructedbytheInterconnectiontimemonitor.
H1istheRMSLimitforthe1Ͳminuteaveragefrequencyerrorfortheinterconnection.
13
Asanoteofinterest,thenewproceduresputforthwithBALͲ003Ͳ1willresultinthereductionofminimumFrequency
BiasSettingvaluesonthemultipleBAinterconnectionstobringthemclosertothenaturalmeasuredFrequency
Responseoftheinterconnection.TherulerequiringaminimumFrequencyBiasSettingof1%ofpeakloadintheNERC
Standardsdatesbackto1962whenNAPSIC,theprecursortotheNERCOperatingCommittee,codifiedthe
recommendationsoftheInterconnectedSystemsGroupmadein1956tosetaminimumof50%ofthenaturalmeasured
responsewhichwas2%ofpeakloadatthattime.The1%figureisnowmorethan200%ofthenaturalmeasured
responsefortheEasternInterconnectionandinsomecasesisapproachingavaluethatcouldresultininstabilitybybeing
toohigh.Thelogicjustifyingaminimumofthenaturalresponseisstillvalid.
14
Thisisconsistentwithcondition3intheReportingACEDefinition:“TheuseofacommonScheduledFrequencyFSforall
areasatalltimes.”
11
V.
AutomaticallyCollectedSourceData
ReportingACEiscalculatedinRealͲtime,atleastasfrequentlyaseverysixseconds15,bytheresponsible
entity’sEnergyManagementSystem(EMS)predominantlybasedonsourcedataautomaticallycollected
bythatsystem.Also,thedatamustbeupdatedatleasteverysixsecondsforcontinuousscantelemetry
andupdatedasneededforreportͲbyͲexceptiontelemetry.
Inaddition,dataqualityinformation(usuallyintheformofdataqualityflagsassociatedwitheachdata
value)mustberetainedandpresentedinrealͲtimetotheSystemOperators.Thisdataquality
informationispresentedtotheSystemOperatortohavesituationalawarenesswithrespecttothe
qualityofthedatainputsandfinalcalculatedresult.Itislaterusedtodeterminewhichdataisvalidfor
useinperformancecalculationssuchasCPS1,BAAL,DCS,andfrequencyresponseobligation(FRM).
NIA(ActualNetInterchange):ThetieͲlinevaluerepresentingeachtieͲlineflowandpseudoͲtiequantity
iscollectedattherequiredscanrateofsixsecondsorless.16,17,18,19Datathatisofquestionableaccuracy
ortimelinessisflaggedwithanappropriatedataqualityflag.Thisinformationispresentedtothe
SystemOperatortosupportsituationalawareness.20TheEMSsumstheindividualflowvaluesonalltie
linesandpseudotieswithalladjacentBAAsatthescanrateandincludesthisvalueasNIAinthe
ReportingACEequationcalculation.TheresultisaseriesofNIAvaluesattheEMSscanrateand
associateddataqualityflags.Theassociateddataqualityofthetelemetryelementispassedtothe
resultofallcalculationsusingthatelement.
NIS(ScheduledNetInterchange):MostinterchangeschedulesandsomeDynamicSchedulesare
enteredintotheEMSinasummaryformateitherasindividualschedules,schedulenetswitheach
AdjacentBalancingAuthorityArea,orafinalScheduledNetInterchange.Theseschedulesareconverted
intoscanͲrateschedulesbytheEMS.TheEMScalculatestheScheduledNetInterchange,where
applicable,bysummingallindividualschedulevaluesornetswitheachAdjacentBalancingAuthority
AreaforallregularandDynamicSchedulesandincludestheresultasNISintheACEequation.
FA(ActualFrequency):Actualfrequencyisprovidedbyafrequencymeasuringdeviceattheaccuracy
specifiedinBALͲ00521attheEMSscanrate.Ifafrequencyvalueisnotavailable,thevalueforthatscan
ismarkedinvalid.
15
BALͲ005Ͳ1BalancingAuthorityControl–“R2.TheBalancingAuthorityAreashallusenogreaterthanasixͲsecondscan
rateinacquiringdatanecessarytocalculateReportingACE.”
16
DatatransmittedatarateslowerthanthescanrateoftheremotesensingequipmentmayrequiretheinclusionofantiͲ
aliasingfilteringatthesourceofthemeasurementtoeliminatetheriskofaliasinginthedatatransmittedtotheEMS.
Seetheattacheddocumenttitled“AntiͲaliasingFiltering.”
17
ItisacceptabletocollecttieͲlineflowdatafromRTUsthatusereportbyexceptionaslongasthoseRTUscansupportthe
scanrateofsixsecondsorlesswhendataischangingrapidlyandbothadjacentBAAsarereceivingcomparabledatato
keepthemeasuredflowsequivalent.
18
ThesixͲsecondscanratenotonlyassuresthatdatacollectedisclosetoRealͲtime,italsolimitsthelatency(timeskew)
associatedwiththedatacollection.
19
Theaccuracyoftheflowdataissetbythoseusingtheflowdatafortransmissionflowmanagement.AswithallACEdata,
aslongasbothadjoiningBAAsareusingthesamevaluesfortieͲlineflow,theeffectsofanyerrorinflowmeasurement
willbeconfinedtothetwoadjacentBAAs.
20
Indicationsofsuspectdataareusuallyindicatedwithcolorchangesand/oralarms.
21
BALͲ005–AutomaticGenerationControlspecifiesanaccuracyofч0.001Hz(equivalenttoч+/Ͳ0.0005Hz)fortheDigital
FrequencyTransducer.
12
IIactual(InadvertentInterchange):ThistermisonlyusedintheWesternInterconnectionACEcalculation.
InadvertentInterchange“Actual”fortheprevioushouriscalculatedbytheEMSfromtheprevious
hour’sdataasthedifferencebetweentheintegratedhourlyaverageScheduledNetInterchangeandthe
integratedhourlyaverageActualNetInterchange.(Blockschedulesarenotusedforthiscalculation.)
t(ManualTimeErrorcorrectionminutesinthehour):ThenumberofminutesofmanualTimeError
correctioninthehour.
VI.
UsesofReportingACE
a. ReportingACEiscurrentlyusedtomeasuresecondaryfrequencycontrolwithinTLBcontrolonallof
theInterconnections.22Consequently,ReportingACEisoneoftheprimarymeasurement
parametersinmanyoftheNERCBalancingStandards.Thefollowingstandardsrequiretheuseof
ReportingACEaspartoftheperformancemetricsorsetrequirementsassociatedwiththe
calculationofReportingACE.
i. BALͲ001Ͳ1–RealPowerBalancingControlPerformanceandBALͲ001Ͳ2–RealPowerBalancing
ControlPerformance.
ii. BALͲ002Ͳ1–DisturbanceControlPerformanceandBALͲ002Ͳ2–DisturbanceControlStandard–
ContingencyReservefromaBalancingContingencyEvent(whenapproved).
iii. BALͲ005Ͳ0.2b–AutomaticGenerationControlandBALͲ005Ͳ1–BalancingAuthorityControl
(whenapproved).
iv. BALͲ006Ͳ2InadvertentInterchange.
b. TheindustrymayalsoconsidertheuseofReportingACEinthefuturetoevaluatetherules
associatedwithtransmissionloading.
VII.
VIII.
IX.
HistoricDataManagement
TheindustrycurrentlyrequirestheretentionofdatasupportingthecalculationofReportingACEand
compliancemeasurementsbasedinpartonReportingACEtosupporttheNERCcomplianceaudit
process.ThisdataretentionmustbeconsideredasanintegralpartoftheReportingACEand“TLB
controlprogram”.
SpecialConditionsandCalculations
IME(InterchangeMeterError):BALͲ005Ͳ1R6requires,“EachBalancingAuthorityAreathatiswithina
multipleBalancingAuthorityAreainterconnectionshallimplementanOperatingProcesstoidentifyand
mitigateerrorsaffectingthescanͲrateaccuracyofdatausedinthecalculationofReportingACE.”
Ideally,errorsidentifiedshouldbecorrectedimmediately,butthisisnotalwayspossible.TheIMEterm,
normallyzero,canbeusedbytheSystemOperatororoperationsstafftoaddacorrectionterminthe
ReportingACEcalculationcorrectingerrorsaffectingthescanͲrateaccuracyofdata,thusmitigatingthe
errorinthecalculationofReportingACEuntiltelemetryerrorscanbecorrected.
22
OnsingleBAAInterconnections,theACEEquationreducestoasingleterm,Ͳ10B(FA–FS),becausetherearenotielines
orschedulestoincludeinthefirstterm,(NIA–NIS),andthereisnoIMEtermtocorrectfortielineordynamicschedule
measurementerrorsinthefirstterm.
13
ThecalculationoftheIMEistheoneoftheresultsofthisrequiredOperatingProcess.It
compensatesfordataorequipmenterrorsaffectingcomponentsofReportingACEidentifiedby
analysisofhistoricdata.TheseerrorsareusuallybetweenintegratedhourlyscanͲratedataand
hourlyaccumulatedmeterdatabutcanalsooccurasdifferencesbetweentheaccumulatedmeter
dataoftwoadjacentBAAs.TheprocessusedforincludingadjustmentsintheIMEtermshouldbe
basedongoodqualitycontrolmethods.23
ThegoalassociatedwiththeuseoftheIMEistoencouragethescanͲratevaluesofactualand
scheduledinterchangebetweenAdjacentBalancingAuthoritiestobeequalinmagnitudeandhave
oppositesigns.24Unfortunately,thesevaluescannotbedirectlycomparedwitheachotherbecause
ofdifferencesbetweenscantimeanddifferencesbetweenscanͲratesbetweenBAAs.Wheninitially
configured,allBAsused“DigitaltoAnalog”convertersand“AnalogtoDigital”converterstotransmit
tieͲlineflowsandaccumulatedMWhvaluesfromthecommonmeteringpointrequiredinthe
standardstotheBA’sEMS.These“DtoA”and“AtoD”convertersaresubjecttoerrorandrequire
frequentcalibration,andalthough,manyhavebeenreplacedbydigitaltelemetry,theystillexistand
requireoversight.AnydifferencebetweenthescanͲratevaluesagreedtobyAdjacentBAAsthatis
notincludedintheerrormitigationprocesswillbepassedtotheinterconnectionformanagement
andwillnotbeincludedintheperformancemeasuressuchasCPS1,BAALandFRM.
EnergyManagementSystemsarecapableofintegratingthescanͲratevaluesusedforthecalculation
ofReportingACEandprovidingthoseintegratedvaluesforcomparisontotheaccumulated
megawattͲhourvaluesforthesamemeters.Iftheintegratedscanratevaluesareclosetothe
accumulatedmegawattͲhourvalues,thenonecanconcludethatthescanͲratevaluesaccurately
representtheaccumulatedvalues.Thefinalstepinthisprocessincludesacomparisonand
agreementontheaccumulatedmegawattͲhourvaluesbetweentheAdjacentBAAssharingthe
measurement.IfthedifferencesbetweenaccumulatedvaluesbetweenAdjacentBAAsisnot
includedinthisprocess,anyadjustmentstotheaccumulatedvaluesmadebyaBAAtoachieve
agreementwithanadjacentBAAwillbeexcludedfromtheanalysisandwillnotbemitigated.This
informationusedinconjunctionwithasimilaranalysisofthescanratevaluesforthesame
measurementbytheAdjacentBalancingAuthorityAreaincludinganalysisofanydifferences
betweentheaccumulatedvaluesandtheagreedtoaccumulatedvalues.Thistotalprocessprovides
reasonableassurancethatthescanͲratetielineflowsorthedynamicschedulesusedbyAdjacent
BAAsareconsistentwithoneanotherconfiningcontrolproblemswithintheboundariesofthe
AdjacentBAAs.
23
AdjustmentstotheIMEtermshouldfollowgoodqualitycontrolmethodsandexcludetamperingasdemonstratedbythe
Deming’sFunnelExperiment,http://blog.newsystemsthinking.com/wͲedwardsͲdemingͲandͲtheͲfunnelͲexperiment/.
24
AslongasthescanͲratetielineflowsandscheduledflowsmatchforAdjacentBalancingAuthorityAreas,anyproblems
withthemeasurementofbalancingontheinterconnectionwillbeconfinedtowithintheboundariesofthoseAdjacent
BalancingAuthorityAreas.Anymismatchwillpassthedifferencetotheinterconnectionandwillresultinfrequency
controlerrorthatwilltobeexcludedfromperformancemeasurementandmanagedbyallBAAsthroughthefrequency
biastermsoftheirReportingACE.
14
TheseerrorcorrectionadjustmentscanbeusedtocorrecterrorsintheNIAorNIS25termsfor
ReportingACEandothermeasurementsthatdependuponanaccurateActualNetInterchange
and/oranaccurateScheduledNetInterchange.Thesamelogicandevaluationprocessesthatare
validforinclusionintheIMEtermoftheReportingACEequationshouldalsobevalidasadjustments
tothescanratetieͲlineflowsusedforthemeasurementofFrequencyResponseaspartoftheBALͲ
003Ͳ1.
a. UseofSourceͲSinkPairsforAsynchronousDCTieLinestoAnotherInterconnection:Oneofthe
primaryrulesforinsuringthevalidityoftheReportingACEequationis,“Allportionsofthe
InterconnectionareincludedinexactlyoneBAAsothatthesumofallBAAs’generation,load,and
lossisthesameastotalInterconnectiongeneration,load,andloss.”Thisisaccomplishedby
requiringtheinclusioninReportingACEofalltielines,pseudoties,interchangeschedulesand
DynamicSchedulestoAdjacentBalancingAuthorityAreasandonlyAdjacentBalancingAuthority
AreasonthesameInterconnection,andrequiringtheexclusionofallasynchronousDCtielinesand
associatedscheduledinterchangewithBalancingAuthorityAreasonadifferentInterconnection
fromReportingACE.Followingthissimpleruleinsuresthatallloads,lossesandgenerationare
properlyincludedwitheachInterconnection.
InsteadofincludingthepowertransfersfromanasynchronousDCtielinebetweentwo
InterconnectionsasanormalinterchangetransferbetweentwoBAAs,thisformofpowertransfer
shouldbeincludedasthoughitisalinkedsourceͲsinkpairforthepurposesofmanagingfrequency
controlwithinatielinebiascontrolprogram.OneterminalofanasynchronousDCtielinewill
appeartothereceivingInterconnectionandreceivingBAAasanenergyresourcesimilartoa
generator.ThisisthesourceendofthesourceͲsinkpair.Theotherterminalofthesame
asynchronousDCtielinewillappeartothesupplyingInterconnectionandsupplyingBAAasan
energysinksimilartoaload.ThisisthesinkendofthesourceͲsinkpair.
InterchangetransactionslinkedtoeitherthesourceorsinkfromotherBAAsonthesame
Interconnectionasthesourceorsinkwillschedulethosetransactions,includethosetransactionsin
ReportingACE,andmanagethosetransactionsinasimilarmannertoanyotherenergytransaction.
OnlytheBAAactingasthesourceorthesinkfortheDCtielinewillexcludetheasynchronoustie
linefromitsReportingACEwhileincludingalltransactionswithAdjacentBAAsonthesame
InterconnectionassociatedwiththatsourceorsinkpowertransferintheirReportingACE.
25
ErrorsintheNISwouldonlyoccurandonlysupportcorrectionincaseswherethereisameasurementerrorassociated
withaDynamicSchedule.
Standards Announcement
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Final Ballots Open through February 8, 2016
Now Available
Final ballots for BAL-005-1 – Balancing Authority Control and FAC-001-3 – Facility Interconnection
Requirements, and the recommended retirement of BAL-006-2 – Inadvertent Interchange are open
through 8 p.m. Eastern, Monday, February 8, 2016.
Balloting
In the final ballot, votes are counted by exception. Only members of the ballot pools may cast a vote. All
ballot pool members may change their previously cast votes. A ballot pool member who failed to vote
during the previous ballot period may vote in the final ballot period. If a ballot pool member does not
participate in the final ballot, the member’s vote from the previous ballot will be carried over as their
vote in the final ballot.
Members of the ballot pools associated with this project may log in and submit their votes for the
standards here. If you experience any difficulties using the Standards Balloting & Commenting System
(SBS), contact Wendy Muller.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps
The voting results for the standards will be posted and announced after the ballots close. If approved,
the standards will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
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 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls
Final Ballots | January – February 2016
2
Standards Announcement
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls
BAL-005-1, BAL-006-2, and FAC-001-3
Final Ballot Results
Now Available
Final ballots for BAL-005-1 –Balancing Authority Control, FAC-001-3 – Facility Interconnection
Requirements, and the recommended retirement of BAL-006-2 – Inadvertent Interchange, concluded 8
p.m. Eastern, Monday, February 8, 2016.
The standards received sufficient affirmative votes for approval. Voting statistics are listed below, and the
following links provide detailed results:
x
BAL-005-1
x
BAL-006-2
x
FAC-001-3
.
Quorum / Approval
BAL-005-1
86.35% / 72.06%
BAL-006-2
86.98% / 94.61%
FAC-001-3
86.67% / 80.15%
Next Steps
The standards will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Balloting Tool (/)
Dashboard (/)
Users
Ballots
Surveys
Legacy SBS (https://standards.nerc.net/)
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1 FN 2 ST
Voting Start Date: 1/29/2016 12:01:00 AM
Voting End Date: 2/8/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 272
Total Ballot Pool: 315
Quorum: 86.35
Weighted Segment Value: 72.06
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
1
78
1
47
0.77
14
0.23
0
8
9
Segment:
2
10
0.9
4
0.4
5
0.5
0
0
1
Segment:
3
72
1
43
0.796
11
0.204
0
8
10
Segment:
4
25
1
18
0.947
1
0.053
0
2
4
Segment:
5
72
1
33
0.717
13
0.283
0
13
13
Segment:
6
44
1
25
0.714
10
0.286
0
5
4
Segment:
7
2
0
0
0
0
0
0
0
2
Segment:
8
2
0.1
1
0.1
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment:
2 3.0.0.00.2
1
0.1
© 2016
- NERC Ver
Machine Name:
ERODVSBSWB01
9
Negative
Votes
w/o
Comment
Abstain
No
Vote
Segment:
10
8
0.8
5
0.5
3
0.3
0
0
0
Totals:
315
7
177
5.044
58
1.956
0
37
43
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Negative
N/A
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
N/A
1
Black Hills Corporation
Wes Wingen
Abstain
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed - Consolidated
Edison Co. of New
York
Chris de Graffenried
Negative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Negative
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Abstain
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia Transmission
Corporation
Jason Snodgrass
Affirmative
N/A
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Negative
N/A
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
Louis Guidry
Douglas Webb
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
Oshani
Pathirane
Abstain
N/A
Nicolas Turcotte
Negative
N/A
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Negative
N/A
1
NB Power Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public Power
District
Jamison Cawley
Affirmative
N/A
1
New York Power
Authority
Salvatore Spagnolo
Negative
N/A
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern
Indiana Public Service
Co.
Charles Raney
Negative
N/A
Scott Miller
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Negative
N/A
1
Oncor Electric Delivery
Rod Kinard
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
N/A
1
Peak Reliability
Jared Shakespeare
Affirmative
N/A
1
PHI - Potomac Electric
Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant County,
Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
1
Sacramento Municipal
Utility District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Tom Hanzlik
Affirmative
N/A
Tammy Porter
Joe Tarantino
Gas Co.
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Negative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
N/A
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent Electricity
System Operator
Leonard Kula
Negative
N/A
2
ISO New England, Inc.
Michael Puscas
Negative
N/A
2
Midcontinent ISO, Inc.
Terry BIlke
Negative
N/A
2
New York Independent
System Operator
Gregory Campoli
Negative
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Charles Yeung
None
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public Utilities
Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Negative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Abstain
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Abstain
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Thomas Mielnik
Negative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Mark Schultz
Affirmative
N/A
Kathleen
Goodman
William Temple
Darnez
Gresham
Springs
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New
York
Peter Yost
Negative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Abstain
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Negative
N/A
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
Bill Hughes
Louis Guidry
Douglas Webb
Oshani
Pathirane
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
N/A
3
National Grid USA
Brian Shanahan
Negative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
New York Power
Authority
David Rivera
Negative
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Ramon Barany
Negative
N/A
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Negative
N/A
3
PHI - Potomac Electric
Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Negative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento Municipal
Utility District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa Electric
Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
Negative
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
Joe Tarantino
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Abstain
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
None
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Affirmative
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Negative
N/A
4
Modesto Irrigation
Spencer Tacke
None
N/A
Bill Hughes
District
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant County,
Washington
Yvonne McMackin
None
N/A
4
Sacramento Municipal
Utility District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Negative
N/A
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Abstain
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Abstain
N/A
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
Joe Tarantino
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
N/A
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of San
Francisco
Daniel Mason
Abstain
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
None
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed - Consolidated
Edison Co. of New
York
Brian O'Boyle
Negative
N/A
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Abstain
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
Kelly Dash
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Abstain
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Abstain
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Affirmative
N/A
5
Great River Energy
Preston Walsh
Negative
N/A
5
Hydro-Qu?bec
Production
Roger Dufresne
Negative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Affirmative
N/A
5
Lower Colorado River
Authority
Dixie Wells
Abstain
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Negative
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
N/A
5
NB Power Corporation
Rob Vance
Negative
N/A
5
Nebraska Public Power
District
Don Schmit
Abstain
N/A
5
New York Power
Authority
Wayne Sipperly
Negative
N/A
Douglas Webb
Scott Miller
5
NextEra Energy
Allen Schriver
Negative
N/A
5
NiSource - Northern
Indiana Public Service
Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Negative
N/A
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Cathy Fogale
Negative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant County,
Washington
Alex Ybarra
Affirmative
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento Municipal
Utility District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
Joe Tarantino
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation, LLC
Donald Lock
Abstain
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa Electric
Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
M Lee Thomas
Negative
N/A
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Abstain
N/A
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Negative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed - Consolidated
Edison Co. of New
Robert Winston
Negative
N/A
York
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Abstain
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Abstain
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power and
Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Negative
N/A
6
Lower Colorado River
Authority
Michael Shaw
None
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
N/A
6
New York Power
Authority
Shivaz Chopra
Negative
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Joe O'Brien
Negative
N/A
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Negative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
N/A
6
Platte River Power
Carol Ballantine
Affirmative
N/A
Nick Braden
Authority
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Negative
N/A
6
Sacramento Municipal
Utility District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa Electric
Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Negative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Frederick Plett
Affirmative
N/A
Joe Tarantino
Amy Casuscelli
Attorney General
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Negative
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Negative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power Pool
Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Negative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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BALLOT RESULTS
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-006-2 FN 2 ST
Voting Start Date: 1/29/2016 12:01:00 AM
Voting End Date: 2/8/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 274
Total Ballot Pool: 315
Quorum: 86.98
Weighted Segment Value: 94.61
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
1
78
1
58
0.967
2
0.033
0
9
9
Segment:
2
10
1
8
0.8
2
0.2
0
0
0
Segment:
3
72
1
55
1
0
0
0
7
10
Segment:
4
25
1
17
1
0
0
0
4
4
Segment:
5
72
1
47
0.979
1
0.021
0
12
12
Segment:
6
44
1
34
0.971
1
0.029
0
5
4
Segment:
7
2
0
0
0
0
0
0
0
2
Segment:
8
2
0.1
1
0.1
0
0
0
1
0
1
0.1
0
0
0
Segment
Segment:
2 3.0.0.00.2
1
0.1
© 2016
- NERC Ver
Machine Name:
ERODVSBSWB02
9
Negative
Votes
w/o
Comment
Abstain
No
Vote
Segment:
10
8
0.8
8
0.8
0
0
0
0
0
Totals:
315
7.1
229
6.717
7
0.383
0
38
41
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
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Designated
Proxy
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Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Affirmative
N/A
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Wes Wingen
Abstain
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed - Consolidated
Edison Co. of New
York
Chris de Graffenried
Affirmative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Affirmative
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Abstain
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Abstain
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia Transmission
Corporation
Jason Snodgrass
Affirmative
N/A
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
Louis Guidry
Douglas Webb
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
Oshani
Pathirane
Abstain
N/A
Nicolas Turcotte
Affirmative
N/A
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public Power
District
Jamison Cawley
Affirmative
N/A
1
New York Power
Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern
Indiana Public Service
Co.
Charles Raney
Affirmative
N/A
Scott Miller
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Affirmative
N/A
1
Oncor Electric Delivery
Rod Kinard
Abstain
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Peak Reliability
Jared Shakespeare
Affirmative
N/A
1
PHI - Potomac Electric
Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant County,
Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
1
Sacramento Municipal
Utility District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Tom Hanzlik
Affirmative
N/A
Tammy Porter
Joe Tarantino
Gas Co.
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Affirmative
N/A
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent Electricity
System Operator
Leonard Kula
Affirmative
N/A
2
ISO New England, Inc.
Michael Puscas
Negative
N/A
2
Midcontinent ISO, Inc.
Terry BIlke
Affirmative
N/A
2
New York Independent
System Operator
Gregory Campoli
Affirmative
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Charles Yeung
Negative
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public Utilities
Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Abstain
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Abstain
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Thomas Mielnik
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Mark Schultz
Affirmative
N/A
Kathleen
Goodman
William Temple
Darnez
Gresham
Springs
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New
York
Peter Yost
Affirmative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Abstain
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Affirmative
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
Jessica Tucker
Affirmative
N/A
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
Bill Hughes
Louis Guidry
Douglas Webb
Oshani
Pathirane
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric System
Jason Fortik
Abstain
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Affirmative
N/A
3
New York Power
Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Ramon Barany
Affirmative
N/A
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Affirmative
N/A
3
PHI - Potomac Electric
Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Affirmative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento Municipal
Utility District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa Electric
Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
Affirmative
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
Joe Tarantino
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Abstain
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
None
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Affirmative
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Abstain
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Affirmative
N/A
4
Modesto Irrigation
Spencer Tacke
None
N/A
Bill Hughes
District
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Abstain
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant County,
Washington
Yvonne McMackin
None
N/A
4
Sacramento Municipal
Utility District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Abstain
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Abstain
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Abstain
N/A
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
Joe Tarantino
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
N/A
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of San
Francisco
Daniel Mason
Abstain
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
None
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed - Consolidated
Edison Co. of New
York
Brian O'Boyle
Affirmative
N/A
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Abstain
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
Kelly Dash
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Abstain
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Abstain
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Affirmative
N/A
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Hydro-Qu?bec
Production
Roger Dufresne
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Affirmative
N/A
5
Lower Colorado River
Authority
Dixie Wells
Abstain
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Affirmative
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Affirmative
N/A
5
NB Power Corporation
Rob Vance
Affirmative
N/A
5
Nebraska Public Power
District
Don Schmit
Affirmative
N/A
5
New York Power
Authority
Wayne Sipperly
Affirmative
N/A
Douglas Webb
Scott Miller
5
NextEra Energy
Allen Schriver
Affirmative
N/A
5
NiSource - Northern
Indiana Public Service
Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Affirmative
N/A
5
Oglethorpe Power
Corporation
Teresa Czyz
None
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Cathy Fogale
Affirmative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
Abstain
N/A
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
Affirmative
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant County,
Washington
Alex Ybarra
Affirmative
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento Municipal
Utility District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
Joe Tarantino
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation, LLC
Donald Lock
Abstain
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa Electric
Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
M Lee Thomas
Affirmative
N/A
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Abstain
N/A
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Abstain
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed - Consolidated
Edison Co. of New
Robert Winston
Affirmative
N/A
York
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Abstain
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Abstain
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power and
Light Co.
Chris Bridges
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Affirmative
N/A
6
Lower Colorado River
Authority
Michael Shaw
None
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Affirmative
N/A
6
New York Power
Authority
Shivaz Chopra
Affirmative
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Joe O'Brien
Affirmative
N/A
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
N/A
6
Platte River Power
Carol Ballantine
Affirmative
N/A
Nick Braden
Authority
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Affirmative
N/A
6
Sacramento Municipal
Utility District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa Electric
Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Frederick Plett
Affirmative
N/A
Joe Tarantino
Amy Casuscelli
Attorney General
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Negative
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Affirmative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power Pool
Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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BALLOT RESULTS
Ballot Name: 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls FAC-001-3 FN 2 ST
Voting Start Date: 1/29/2016 12:01:00 AM
Voting End Date: 2/8/2016 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 273
Total Ballot Pool: 315
Quorum: 86.67
Weighted Segment Value: 80.15
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
1
78
1
50
0.781
14
0.219
0
4
10
Segment:
2
10
0.9
5
0.5
4
0.4
0
0
1
Segment:
3
72
1
49
0.817
11
0.183
0
2
10
Segment:
4
25
1
19
0.95
1
0.05
0
2
3
Segment:
5
72
1
44
0.786
12
0.214
0
4
12
Segment:
6
44
1
31
0.816
7
0.184
0
2
4
Segment:
7
2
0
0
0
0
0
0
0
2
Segment:
8
2
0.1
1
0.1
0
0
0
1
0
0
0
0
1
0
Segment
Segment:
2 3.0.0.00.1
1
0.1
© 2016
- NERC Ver
Machine Name:
ERODVSBSWB01
9
Negative
Votes
w/o
Comment
Abstain
No
Vote
Segment:
10
8
0.7
6
0.6
1
0.1
0
1
0
Totals:
315
6.8
206
5.45
50
1.35
0
17
42
BALLOT POOL MEMBERS
Show
All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
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Ballot
NERC
Memo
1
Ameren - Ameren
Services
Eric Scott
Affirmative
N/A
1
American
Transmission
Company, LLC
Andrew Pusztai
Abstain
N/A
1
APS - Arizona Public
Service Co.
Michelle Amarantos
Affirmative
N/A
1
Associated Electric
Cooperative, Inc.
Phil Hart
Affirmative
N/A
1
Avista - Avista
Corporation
Bryan Cox
Rich Hydzik
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia Robertson
Affirmative
N/A
1
Beaches Energy
Services
Don Cuevas
Affirmative
N/A
1
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Terry Harbour
Negative
N/A
1
Black Hills Corporation
Wes Wingen
Affirmative
N/A
1
Bonneville Power
Administration
Donald Watkins
Affirmative
N/A
1
Brazos Electric Power
Cooperative, Inc.
Tony Kroskey
None
N/A
1
Bryan Texas Utilities
John Fontenot
Affirmative
N/A
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Affirmative
N/A
1
Colorado Springs
Utilities
Shawna Speer
None
N/A
1
Con Ed - Consolidated
Edison Co. of New
York
Chris de Graffenried
Negative
N/A
1
Dairyland Power
Cooperative
Robert Roddy
Negative
N/A
1
Dominion - Dominion
Virginia Power
Larry Nash
Negative
N/A
1
Duke Energy
Doug Hils
Affirmative
N/A
1
Edison International Southern California
Edison Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy
Services, Inc.
Oliver Burke
Affirmative
N/A
1
Exelon
Chris Scanlon
Affirmative
N/A
1
FirstEnergy FirstEnergy
Corporation
William Smith
Affirmative
N/A
1
Georgia Transmission
Corporation
Jason Snodgrass
Negative
N/A
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Negative
N/A
1
Great River Energy
Gordon Pietsch
None
N/A
1
Hoosier Energy Rural
Electric Cooperative,
Inc.
Bob Solomon
None
N/A
Louis Guidry
Douglas Webb
1
Hydro One Networks,
Inc.
Payam Farahbakhsh
1
Hydro-Qu?bec
TransEnergie
1
Oshani
Pathirane
Abstain
N/A
Nicolas Turcotte
Abstain
N/A
IDACORP - Idaho
Power Company
Laura Nelson
Affirmative
N/A
1
International
Transmission
Company Holdings
Corporation
Michael Moltane
Abstain
N/A
1
KAMO Electric
Cooperative
Walter Kenyon
Affirmative
N/A
1
Los Angeles
Department of Water
and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Mike Smith
Affirmative
N/A
1
MEAG Power
David Weekley
Affirmative
N/A
1
Muscatine Power and
Water
Andy Kurriger
Negative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Alan MacNaughton
None
N/A
1
Nebraska Public Power
District
Jamison Cawley
Negative
N/A
1
New York Power
Authority
Salvatore Spagnolo
Negative
N/A
1
NextEra Energy Florida Power and
Light Co.
Mike ONeil
Negative
N/A
1
NiSource - Northern
Indiana Public Service
Co.
Charles Raney
Negative
N/A
Scott Miller
1
Northeast Missouri
Electric Power
Cooperative
Kevin White
Affirmative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy Oklahoma Gas and
Electric Co.
Terri Pyle
Affirmative
N/A
1
Oncor Electric Delivery
Rod Kinard
Negative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Negative
N/A
1
Peak Reliability
Jared Shakespeare
Affirmative
N/A
1
PHI - Potomac Electric
Power Co.
David Thorne
Affirmative
N/A
1
Platte River Power
Authority
John Collins
Affirmative
N/A
1
PNM Resources Public Service
Company of New
Mexico
Laurie Williams
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Affirmative
N/A
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District
No. 1 of Snohomish
County
Long Duong
Affirmative
N/A
1
Public Utility District
No. 2 of Grant County,
Washington
Michiko Sell
None
N/A
1
Puget Sound Energy,
Inc.
Theresa Rakowsky
Affirmative
N/A
1
Sacramento Municipal
Utility District
Tim Kelley
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South
Carolina Electric and
Tom Hanzlik
Affirmative
N/A
Tammy Porter
Joe Tarantino
Gas Co.
1
Seattle City Light
Pawel Krupa
Michael
Watkins
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Bret Galbraith
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Denise Stevens
Affirmative
N/A
1
Southern Company Southern Company
Services, Inc.
Robert A. Schaffeld
Affirmative
N/A
1
Southwest
Transmission
Cooperative, Inc.
John Shaver
Negative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric
(City of Tallahassee,
FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley
Authority
Howell Scott
Affirmative
N/A
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Affirmative
N/A
1
Unisource - Tucson
Electric Power Co.
John Tolo
None
N/A
1
United Illuminating Co.
Jonathan Appelbaum
Affirmative
N/A
1
Westar Energy
Kevin Giles
Affirmative
N/A
1
Western Area Power
Administration
Steve Johnson
None
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
BC Hydro and Power
Authority
Venkataramakrishnan
Vinnakota
Affirmative
N/A
2
California ISO
Richard Vine
Affirmative
N/A
2
Electric Reliability
Council of Texas, Inc.
Elizabeth Axson
Negative
N/A
2
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
2
Independent Electricity
System Operator
Leonard Kula
Affirmative
N/A
2
ISO New England, Inc.
Michael Puscas
Negative
N/A
2
Midcontinent ISO, Inc.
Terry BIlke
Negative
N/A
2
New York Independent
System Operator
Gregory Campoli
Negative
N/A
2
PJM Interconnection,
L.L.C.
Mark Holman
Affirmative
N/A
2
Southwest Power Pool,
Inc. (RTO)
Charles Yeung
None
N/A
3
Ameren - Ameren
Services
David Jendras
Affirmative
N/A
3
Anaheim Public Utilities
Dept.
Dennis Schmidt
None
N/A
3
APS - Arizona Public
Service Co.
Jeri Freimuth
Affirmative
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Affirmative
N/A
3
Austin Energy
Shuye Teng
Affirmative
N/A
3
Avista - Avista
Corporation
Scott Kinney
Affirmative
N/A
3
Basin Electric Power
Cooperative
Jeremy Voll
Negative
N/A
3
BC Hydro and Power
Authority
Faramarz Amjadi
Affirmative
N/A
3
Beaches Energy
Services
Steven Lancaster
Affirmative
N/A
3
Berkshire Hathaway
Energy - MidAmerican
Energy Co.
Thomas Mielnik
Negative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City of Green Cove
Mark Schultz
Affirmative
N/A
Kathleen
Goodman
William Temple
Darnez
Gresham
Springs
3
City of Leesburg
Chris Adkins
Affirmative
N/A
3
City of Redding
Elizabeth Hadley
Affirmative
N/A
3
Clark Public Utilities
Jack Stamper
None
N/A
3
Cleco Corporation
Michelle Corley
Affirmative
N/A
3
CMS Energy Consumers Energy
Company
Karl Blaszkowski
Affirmative
N/A
3
Colorado Springs
Utilities
Hillary Dobson
None
N/A
3
Con Ed - Consolidated
Edison Co. of New
York
Peter Yost
Negative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Negative
N/A
3
DTE Energy - Detroit
Edison Company
Karie Barczak
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California
Edison Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
Affirmative
N/A
3
FirstEnergy FirstEnergy
Corporation
Theresa Ciancio
Affirmative
N/A
3
Florida Municipal
Power Agency
Joe McKinney
Affirmative
N/A
3
Georgia System
Operations
Corporation
Scott McGough
Negative
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
Jessica Tucker
Negative
N/A
3
Great River Energy
Brian Glover
Negative
N/A
3
Hydro One Networks,
Inc.
Paul Malozewski
Abstain
N/A
Bill Hughes
Louis Guidry
Douglas Webb
Oshani
Pathirane
3
JEA
Garry Baker
None
N/A
3
KAMO Electric
Cooperative
Ted Hilmes
Affirmative
N/A
3
Lakeland Electric
David Hadzima
None
N/A
3
Lincoln Electric System
Jason Fortik
Negative
N/A
3
Los Angeles
Department of Water
and Power
Mike Anctil
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Affirmative
N/A
3
MEAG Power
Roger Brand
Scott Miller
Affirmative
N/A
3
Modesto Irrigation
District
Jack Savage
Nick Braden
Affirmative
N/A
3
Muscatine Power and
Water
Seth Shoemaker
Negative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Negative
N/A
3
New York Power
Authority
David Rivera
Negative
N/A
3
NiSource - Northern
Indiana Public Service
Co.
Ramon Barany
Abstain
N/A
3
Northeast Missouri
Electric Power
Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy Oklahoma Gas and
Electric Co.
Donald Hargrove
Affirmative
N/A
3
PHI - Potomac Electric
Power Co.
Mark Yerger
Affirmative
N/A
3
PNM Resources
Michael Mertz
None
N/A
3
PPL - Louisville Gas
and Electric Co.
Charles Freibert
Affirmative
N/A
3
PSEG - Public Service
Electric and Gas Co.
Jeffrey Mueller
Affirmative
N/A
3
Public Utility District
No. 1 of Okanogan
County
Dale Dunckel
None
N/A
3
Puget Sound Energy,
Inc.
Andrea Basinski
Affirmative
N/A
3
Sacramento Municipal
Utility District
Rachel Moore
Affirmative
N/A
3
Salt River Project
John Coggins
None
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South
Carolina Electric and
Gas Co.
Clay Young
Affirmative
N/A
3
Seattle City Light
Dana Wheelock
Affirmative
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County
PUD No. 1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power
Company
R. Scott Moore
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tallahassee Electric
(City of Tallahassee,
FL)
John Williams
Affirmative
N/A
3
TECO - Tampa Electric
Co.
Ronald Donahey
None
N/A
3
Tennessee Valley
Authority
Ian Grant
Affirmative
N/A
3
Tri-State G and T
Association, Inc.
Janelle Marriott Gill
Affirmative
N/A
Joe Tarantino
3
Turlock Irrigation
District
James Ramos
None
N/A
3
WEC Energy Group,
Inc.
James Keller
Affirmative
N/A
3
Westar Energy
Bo Jones
Affirmative
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy
Corporation Services,
Inc.
Kenneth Goldsmith
Affirmative
N/A
4
Austin Energy
Tina Garvey
Affirmative
N/A
4
Blue Ridge Power
Agency
Duane Dahlquist
Affirmative
N/A
4
City of Clewiston
Lynne Mila
Affirmative
N/A
4
City of New Smyrna
Beach Utilities
Commission
Tim Beyrle
Affirmative
N/A
4
City of Redding
Nick Zettel
Affirmative
N/A
4
CMS Energy Consumers Energy
Company
Julie Hegedus
Affirmative
N/A
4
DTE Energy - Detroit
Edison Company
Daniel Herring
Affirmative
N/A
4
FirstEnergy - Ohio
Edison Company
Doug Hohlbaugh
Affirmative
N/A
4
Florida Municipal
Power Agency
Carol Chinn
Affirmative
N/A
4
Georgia System
Operations
Corporation
Guy Andrews
Abstain
N/A
4
Illinois Municipal
Electric Agency
Bob Thomas
Affirmative
N/A
4
Keys Energy Services
Stanley Rzad
Affirmative
N/A
4
MGE Energy Madison Gas and
Electric Co.
Joseph DePoorter
Negative
N/A
4
Modesto Irrigation
Spencer Tacke
None
N/A
Bill Hughes
District
4
Oklahoma Municipal
Power Authority
Ashley Stringer
Affirmative
N/A
4
Public Utility District
No. 1 of Snohomish
County
John Martinsen
Affirmative
N/A
4
Public Utility District
No. 2 of Grant County,
Washington
Yvonne McMackin
None
N/A
4
Sacramento Municipal
Utility District
Michael Ramirez
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Seminole Electric
Cooperative, Inc.
Michael Ward
Affirmative
N/A
4
South Mississippi
Electric Power
Association
Steve McElhaney
None
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
N/A
4
WEC Energy Group,
Inc.
Anthony Jankowski
Affirmative
N/A
5
AEP
Thomas Foltz
Affirmative
N/A
5
Ameren - Ameren
Missouri
Sam Dwyer
Affirmative
N/A
5
APS - Arizona Public
Service Co.
Stephanie Little
Affirmative
N/A
5
Associated Electric
Cooperative, Inc.
Matthew Pacobit
None
N/A
5
Austin Energy
Jeanie Doty
Affirmative
N/A
5
Avista - Avista
Corporation
Steve Wenke
Affirmative
N/A
5
Basin Electric Power
Cooperative
Mike Kraft
Negative
N/A
5
BC Hydro and Power
Authority
Clement Ma
Affirmative
N/A
Joe Tarantino
5
Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Francis Halpin
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
N/A
5
Calpine Corporation
Hamid Zakery
None
N/A
5
Choctaw Generation
Limited Partnership,
LLLP
Rob Watson
Affirmative
N/A
5
City and County of San
Francisco
Daniel Mason
Affirmative
N/A
5
City of Independence,
Power and Light
Department
Jim Nail
Affirmative
N/A
5
City of Redding
Paul Cummings
Bill Hughes
Affirmative
N/A
5
Cleco Corporation
Stephanie Huffman
Louis Guidry
Affirmative
N/A
5
CMS Energy Consumers Energy
Company
David Greyerbiehl
Affirmative
N/A
5
Cogentrix Energy
Power Management,
LLC
Mike Hirst
None
N/A
5
Colorado Springs
Utilities
Jeff Icke
None
N/A
5
Con Ed - Consolidated
Edison Co. of New
York
Brian O'Boyle
Negative
N/A
5
Dominion - Dominion
Resources, Inc.
Randi Heise
Abstain
N/A
5
DTE Energy - Detroit
Edison Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California
Edison Company
Michael McSpadden
Affirmative
N/A
Kelly Dash
5
Entergy - Entergy
Services, Inc.
Tracey Stubbs
None
N/A
5
Exelon
Vince Catania
Affirmative
N/A
5
FirstEnergy FirstEnergy Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal
Power Agency
David Schumann
Affirmative
N/A
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Negative
N/A
5
Great River Energy
Preston Walsh
Negative
N/A
5
Hydro-Qu?bec
Production
Roger Dufresne
Abstain
N/A
5
JEA
John Babik
Affirmative
N/A
5
Lakeland Electric
Jim Howard
None
N/A
5
Lincoln Electric System
Kayleigh Wilkerson
Negative
N/A
5
Los Angeles
Department of Water
and Power
Kenneth Silver
Affirmative
N/A
5
Lower Colorado River
Authority
Dixie Wells
Negative
N/A
5
Luminant - Luminant
Generation Company
LLC
Rick Terrill
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Affirmative
N/A
5
Massachusetts
Municipal Wholesale
Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Affirmative
N/A
5
Muscatine Power and
Water
Mike Avesing
Negative
N/A
5
NB Power Corporation
Rob Vance
Abstain
N/A
5
Nebraska Public Power
District
Don Schmit
Negative
N/A
5
New York Power
Authority
Wayne Sipperly
Negative
N/A
Douglas Webb
Scott Miller
5
NextEra Energy
Allen Schriver
Affirmative
N/A
5
NiSource - Northern
Indiana Public Service
Co.
Michael Melvin
None
N/A
5
OGE Energy Oklahoma Gas and
Electric Co.
Leo Staples
Affirmative
N/A
5
Oglethorpe Power
Corporation
Bernard Johnson
Negative
N/A
5
Omaha Public Power
District
Mahmood Safi
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Cathy Fogale
Negative
N/A
5
Pacific Gas and
Electric Company
Alex Chua
None
N/A
5
Platte River Power
Authority
Tyson Archie
Affirmative
N/A
5
Portland General
Electric Co.
Matt Jastram
None
N/A
5
PPL Electric Utilities
Corporation
Dan Wilson
None
N/A
5
PSEG - PSEG Fossil
LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District
No. 1 of Snohomish
County
Sam Nietfeld
Affirmative
N/A
5
Public Utility District
No. 2 of Grant County,
Washington
Alex Ybarra
Affirmative
N/A
5
Puget Sound Energy,
Inc.
Lynda Kupfer
Affirmative
N/A
5
Sacramento Municipal
Utility District
Susan Gill-Zobitz
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
SCANA - South
Carolina Electric and
Gas Co.
Henry Delk
None
N/A
Joe Tarantino
5
Seattle City Light
Mike Haynes
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Chris Mattson
Affirmative
N/A
5
Talen Generation, LLC
Donald Lock
Affirmative
N/A
5
Tallahassee Electric
(City of Tallahassee,
FL)
Karen Webb
Affirmative
N/A
5
TECO - Tampa Electric
Co.
R James Rocha
None
N/A
5
Tennessee Valley
Authority
M Lee Thomas
Affirmative
N/A
5
WEC Energy Group,
Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
stephanie johnson
Affirmative
N/A
5
Xcel Energy, Inc.
David Lemmons
Affirmative
N/A
6
Ameren - Ameren
Services
Robert Quinlivan
Affirmative
N/A
6
APS - Arizona Public
Service Co.
Bobbi Welch
Affirmative
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Affirmative
N/A
6
Bonneville Power
Administration
Alex Spain
Affirmative
N/A
6
City of Redding
Marvin Briggs
Bill Hughes
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Louis Guidry
Affirmative
N/A
6
Colorado Springs
Utilities
Shannon Fair
None
N/A
6
Con Ed - Consolidated
Edison Co. of New
Robert Winston
Negative
N/A
York
6
Dominion - Dominion
Resources, Inc.
Louis Slade
Negative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Exelon
Dave Carlson
Affirmative
N/A
6
FirstEnergy FirstEnergy Solutions
Ann Ivanc
Affirmative
N/A
6
Florida Municipal
Power Agency
Richard Montgomery
Affirmative
N/A
6
Florida Municipal
Power Pool
Tom Reedy
Chris Gowder
Affirmative
N/A
6
Great Plains Energy Kansas City Power and
Light Co.
Chris Bridges
Douglas Webb
Negative
N/A
6
Great River Energy
Donna Stephenson
Michael
Brytowski
Negative
N/A
6
Lower Colorado River
Authority
Michael Shaw
None
N/A
6
Manitoba Hydro
Blair Mukanik
Affirmative
N/A
6
Modesto Irrigation
District
James McFall
Affirmative
N/A
6
Muscatine Power and
Water
Ryan Streck
Negative
N/A
6
New York Power
Authority
Shivaz Chopra
Negative
N/A
6
NextEra Energy Florida Power and
Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern
Indiana Public Service
Co.
Joe O'Brien
Abstain
N/A
6
OGE Energy Oklahoma Gas and
Electric Co.
Jerry Nottnagel
Affirmative
N/A
6
Oglethorpe Power
Corporation
Donna Johnson
Negative
N/A
6
Platte River Power
Carol Ballantine
Affirmative
N/A
Nick Braden
Authority
6
Portland General
Electric Co.
Shawn Davis
None
N/A
6
PPL - Louisville Gas
and Electric Co.
OELKER LINN
Affirmative
N/A
6
Sacramento Municipal
Utility District
Diane Clark
Affirmative
N/A
6
Salt River Project
William Abraham
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Affirmative
N/A
6
Snohomish County
PUD No. 1
Kenn Backholm
Affirmative
N/A
6
Southern Company Southern Company
Generation and
Energy Marketing
John J. Ciza
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Talen Energy
Marketing, LLC
Elizabeth Davis
Abstain
N/A
6
TECO - Tampa Electric
Co.
Benjamin Smith
None
N/A
6
Tennessee Valley
Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group,
Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Megan Wagner
Affirmative
N/A
6
Xcel Energy, Inc.
Peter Colussy
Affirmative
N/A
7
Exxon Mobil
Jay Barnett
None
N/A
7
Luminant Mining
Company LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
8
Massachusetts
Frederick Plett
Affirmative
N/A
Joe Tarantino
Amy Casuscelli
Attorney General
9
City of Vero Beach
Ginny Beigel
Affirmative
N/A
9
Commonwealth of
Massachusetts
Department of Public
Utilities
Donald Nelson
Abstain
N/A
10
Florida Reliability
Coordinating Council
Peter Heidrich
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
David Greene
Affirmative
N/A
10
Southwest Power Pool
Regional Entity
Bob Reynolds
Affirmative
N/A
10
Texas Reliability Entity,
Inc.
Rachel Coyne
Affirmative
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Previous
Showing 1 to 315 of 315 entries
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Exhibit O
Standard Drafting Team Roster
Standard Drafting Team Roster
Project 2010-14.2.1 Phase 2 of Balancing Authority
Reliability-based Controls – BAL-005, BAL-006, FAC-001
Participant
Entity
Chair
Jerry Rust
Northwest Power Pool
Vice Chair
Thomas W. Siegrist
Brickfield Burchette Ritts and Stone, PC
Member
Brad Gordon
PJM Interconnection LLC
Phillip Hart
AECI
Doug Hils
Duke Energy
Howard Illian
Energy Mark, Inc.
Gary Nolan
Arizona Public Service
Michael Potishnak
Spriteland Energy representing NPCC
Sandip Sharma
Electric Reliability Council of Texas, Inc.
Steve Swan
Midwest ISO, Inc.
Darrel Richardson – Senior
Standards Developer
North American Electric Reliability Corporation
NERC Staff
Candice Castaneda – Counsel North American Electric Reliability Corporation
Andrew Wills – Associate
Counsel
North American Electric Reliability Corporation
| File Type | application/octet-stream |
| File Title | NERC |
| File Modified | 0000-00-00 |
| File Created | 0000-00-00 |